GLOSSARY OF TERMS

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

Entities

Board of Directors means the Board of Directors of Penn West Petroleum Ltd.

Penn West, we, us, our or Trust means Penn West Energy Trust and all its controlled entities on a consolidated basis.

Penn West Partnership means Penn West Petroleum, a general partnership, between Penn West Petroleum Ltd. and Trocana Resources Inc., a wholly owned subsidiary of Penn West Petroleum Ltd.

Trustee means CIBC Mellon Trust Company, our trustee.

Unitholders means holders of our Trust Units.

Independent Engineering

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

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

Securities

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

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

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

Agreements

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

NPI Agreements means the net profits interest agreement dated May 31, 2005 between Penn West Petroleum Ltd. and the Trust, the net profit interest agreement dated November 8, 2005 between Penn West Petroleum Ltd. and the Trust and the net profits interest agreement dated November 8, 2005 between Petrofund Ventures Trust, one of our wholly owned trusts, and the Trust.

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

Others

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

ABBREVIATIONS

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

Other
BOE or boe		means barrel of oil equivalent, using the conversion factor of 6 Mcf of natural gas being equivalent to one barrel of oil. Boes may be misleading, particularly if used in isolation. A boe conversion ratio of 6 Mcf: 1 bbl is based on an energy equivalency conversion method primarily applicable at the burner tip and does not represent a value equivalency at the wellhead.
WTI		means West Texas Intermediate.
°API		means the measure of the density or gravity of liquid petroleum products derived from a specific gravity.
psi		means pounds per square inch.
MM$		one million dollars

CONVERSIONS

The following table 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	2.471
gigajoules	MMbtu	0.950
MMbtu	gigajoules	1.0526

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

SPECIAL NOTE REGARDING FORWARD-LOOKING STATEMENTS

Certain statements contained in this Annual Information Form and in certain documents incorporated by reference into this Annual Information Form, constitute forward-looking statements. These statements relate to future events or our future performance. All statements other than statements of historical fact may be forward-looking statements. Forward-looking statements are often, but not always, identified by the use of words such as “seek”, “anticipate”, “budget”, “plan”, “continue”, “estimate”, “expect”, “forecast”, “may”, “will”, “project”, “predict”, “potential”, “targeting”, “intend”, “could”, “might”, “should”, “believe” and other similar expressions. These statements involve known and unknown risks, uncertainties and other factors that may cause actual results or events to differ materially from those anticipated in such forward-looking statements. We believe the expectations reflected in those forward-looking statements are reasonable but no assurance can be given that these expectations will prove to be correct and such forward-looking statements included in, or incorporated by reference into, this Annual Information Form should not be unduly relied upon. These statements speak only as of the date of this Annual Information Form or as of the date specified in the documents incorporated by reference into this Annual Information Form, as the case may be.

In particular, this Annual Information Form, and the documents incorporated by reference, contain forward-looking statements based on assumptions pertaining to the following:

· the performance characteristics of our oil and natural gas properties;

· oil and natural gas production levels;

· the size of our oil and natural gas reserves;

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

· supply and demand for oil and natural gas;

· expectations regarding our ability to raise capital and to continually add to reserves through acquisitions and development;

· treatment under governmental regulatory regimes and tax laws; and

· capital expenditures programs.

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

· volatility in market prices for oil and natural gas;

· liabilities inherent in oil and natural gas operations;

· uncertainties associated with estimating oil and natural gas reserves;

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

· incorrect assessments of the value of acquisitions;

· geological, technical, drilling and processing problems;

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

· the other factors discussed under “Risk Factors”.

The actual results could differ materially from those results anticipated in these forward-looking statements, which are based on assumptions, including: the market prices for oil and natural gas; the continued availability of capital, acquisitions of reserves, undeveloped lands and skilled personnel; the continuation of the current tax and regulatory regime; and other assumptions contained in this Annual Information Form.

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 resources and reserves described can be profitably produced in the future. Readers are cautioned that the foregoing lists of factors are not exhaustive. The forward-looking statements contained in this Annual Information Form and the documents incorporated by reference herein are expressly qualified by this cautionary statement. We do not undertake any obligation to publicly update or revise any forward-looking statements.

Description of Cash Flow

This Annual Information Form refers to cash flow and cash flow from operations derived from cash flow from operating activities (before changes in non-cash working capital, expenditures on abandonment and reclamation costs and payments for surrendered stock options). Cash flow as presented does not have any standardized meaning prescribed by Canadian generally accepted accounting principles, (“GAAP”) and therefore it may not be comparable with the calculation of similar

measures for other entities. Cash flow as presented is not intended to represent operating cash flow or operating profits for the period nor should it be viewed as an alternative to cash flow from operating activities, net earnings or other measures of financial performance calculated in accordance with Canadian GAAP.

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

Access to Documents

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

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 as amended and restated on June 30, 2006. At that time, CIBC Mellon Trust Company was appointed as trustee under the Trust Indenture for a three year period. The beneficiaries of the Trust are holders of the Trust Units. Our principal and head office is located at 2200, 425 — 1st Street S.W., Calgary, Alberta, T2P 3L8.

We commenced operations in our current structure on June 1, 2005 after the completion of a plan of arrangement under the Business Corporations Act (Alberta). Pursuant to this plan of arrangement, holders of common shares of Penn West Petroleum Ltd. received three (3) Trust Units for each one (1) of their common shares.

Inter-Corporate Relationships

The following are the names, the percentage of voting securities that we own and the jurisdiction of incorporation, continuance or formation of our material subsidiaries and partnerships either, direct or indirect, as at the date hereof.

	Percentage of voting securities (directly or indirectly)	Nature of Entity	Jurisdiction of Incorporation/ Formation
Penn West Petroleum Ltd.	100%	Corporation	Alberta
Penn West Petroleum	100%	General Partnership	Alberta

Our Organization Structure

The following diagram describes the inter-corporate relationships among us and our material subsidiaries.

Notes:

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

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

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

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

GENERAL DEVELOPMENT OF THE BUSINESS

History and Development

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

Effective June 30, 2006 Penn West completed the Petrofund Merger, pursuant to which Penn West acquired Petrofund Energy Trust on the basis of an exchange of .60 of a Trust Unit (an aggregate of 70.7 million Trust Units). A special cash distribution in the amount of $1.10 per unit (an aggregate of $129.6 million) of Petrofund Energy Trust, 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 Merger to the holders of units of Petrofund Energy Trust. As a result of the acquisition pursuant to the Petrofund Merger, Penn West acquired 70.9 MMbbl of light/medium crude oil and NGLs, 0.7 MMbbl of heavy oil and 279.3 Bcf of natural gas on a proved reserve basis and 93.8 MMbbl of light/medium crude oil and NGLs, 1.0 MMbbl of heavy oil, 371.2 Bcf of natural gas on a proved plus probable reserve basis and 352,600 net acres of undeveloped land. Penn West assumed $610.4 million of bank indebtedness of Petrofund Energy Trust in connection with the Petrofund Merger.

For further information in relation to the Petrofund Merger, see note 3 of our consolidated financial statements for the year ended December 31, 2006, which is hereby incorporated by reference and which has been filed on SEDAR at www.sedar.com.

DESCRIPTION OF OUR BUSINESS

Overview

Our principal undertaking is to issue Trust Units and to acquire and hold securities of subsidiaries, trusts and partnerships, net profits interests, royalties, notes and other interests. Our direct and indirect subsidiaries and partnerships 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 cash flow from the assets is paid from Penn West Petroleum Ltd. and Petrofund Ventures Trust to the Trust by way of interest and principal payments on the Notes and payments from Penn West Petroleum Ltd. and Petrofund Ventures Trust to the Trust 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 Penn West Petroleum Ltd. and Petrofund Ventures Trust by way of interest received on the principal amount of Notes and payments pursuant to the NPI. 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.

Penn West Petroleum Ltd.

Penn West Petroleum Ltd. is a corporation amalgamated and subsisting pursuant to the laws of Alberta. Penn West Petroleum Ltd. 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 Penn West Petroleum Ltd.

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

Notes

The Notes evidence the indebtedness of Penn West Petroleum Ltd. and Petrofund Ventures Trust to the Trust in connection with the plan of arrangement completed on May 31, 2005 and additional promissory notes acquired on the acquisition of Petrofund Energy Trust pursuant to the Petrofund Merger. The Notes from Penn West Petroleum Ltd. are unsecured and subordinated to senior indebtedness and bear interest at rates ranging from 11.25 percent to 13.00 percent per annum and require principal payments at dates ranging from May 31, 2017 to January 1, 2019. The Note from Petrofund Ventures Trust bears interest at a rate of six percent per annum and is payable on demand.

NPI

The Trust is a party to NPI Agreements with Penn West Petroleum Ltd. and Petrofund Ventures Trust pursuant to which we have the right to receive the NPIs on petroleum and natural gas rights held by Penn West Petroleum Ltd. and Petrofund Ventures Trust from time to time. Pursuant to the terms of the agreements, we are entitled to a payment from Penn West Petroleum Ltd. and Petrofund Ventures Trust 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 Penn West Petroleum Ltd. and Petrofund Ventures Trust for such month exceeds 99 percent of certain deductible costs for such period. Deductible costs generally include capital expenditures, royalties and operating costs related to oil and gas activities. The term of the agreement is for as long as there are petroleum and natural gas rights to which the NPIs apply.

Proposed Federal Tax Changes

On October 31, 2006 the Federal Minister of Finance proposed to apply a tax at the trust level on distributions of certain income from publicly traded mutual fund trusts at rates of tax comparable to the combined federal and provincial corporate tax and to treat such distributions as dividends to the unitholders (the “October 31 Proposals”). On December 21, 2006 the Federal Minister of Finance released draft legislation to implement the October 31 Proposals pursuant to which, commencing January 1, 2011 (provided Penn West only experiences “normal growth” and no “undue expansion” before then) certain distributions from us which would have otherwise been taxed as ordinary income will be characterized as dividends to our Unitholders and will be subject to tax at corporate rates at the Trust level. Assuming the October 31 Proposals are ultimately enacted in their current form, the implementation of such legislation would be 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).

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

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

STATEMENT OF RESERVES DATA

The Trust’s 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, 2006 and the preparation date of the Statement is February 28, 2007. The Report of Management and Directors on Oil and Gas Disclosure on Form 51-101F3 and the Report on Reserves Data by GLJ on Form 51-102F2 are attached as Appendices A and B to this Annual Information Form.

Disclosure of Reserves Data

The reserves data set forth below is based upon an evaluation by GLJ with an effective date of December 31, 2006 contained in the GLJ Report dated February 28, 2007. 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 constant prices and costs and forecast prices and costs, not including the impact of any hedging activities. The reserves data conforms with the requirements of National Instrument 51-101. We engaged GLJ to provide an evaluation of proved and proved plus probable reserves. See also “Definitions and Notes to Reserve Data Tables” below.

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

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 constant prices and costs assumptions and 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 — Reserve Estimates” and “Risk Factors — Volatility of Oil and Natural Gas Prices”.

We are a taxable entity under the Income Tax Act (Canada) and, at the current time, are generally taxable only on income that is not distributed or distributable to Unitholders. As we currently distribute all our taxable income to Unitholders as required by the Trust Indenture, future net revenue after income taxes is not included in the disclosure tables. The proposed tax on income trust distributions, proposed by the Federal Finance Minister on October 31, 2006, has not been substantively enacted as income tax law. See “Risk Factors — Proposed Federal Tax Changes”.

Reserves Data (Constant Prices and Costs)

SUMMARY OF OIL AND GAS RESERVES
AND NET PRESENT VALUES OF FUTURE NET REVENUE
as of December 31, 2006
CONSTANT PRICES AND COSTS

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

PROVED
Developed Producing	147,890	133,852	41,023	37,482
Developed Non-Producing	6,469	5,876	3,197	2,586
Undeveloped	33,706	29,773	1,841	1,533
TOTAL PROVED	188,066	169,500	46,062	41,600

PROBABLE	50,788	44,969	13,950	12,225

TOTAL PROVED PLUS PROBABLE	238,853	214,469	60,012	53,825

	RESERVES
	NATURAL GAS		NATURAL GAS LIQUIDS
RESERVES CATEGORY	Gross (MMcf)	Net (MMcf)	Gross (Mbbl)	Net (Mbbl)

PROVED
Developed Producing	662,497	542,168	17,079	11,849
Developed Non-Producing	46,379	35,964	1,025	692
Undeveloped	43,028	35,060	1,469	1,019
TOTAL PROVED	751,904	613,191	19,573	13,560

PROBABLE	201,199	165,627	5,272	3,808

TOTAL PROVED PLUS PROBABLE	953,104	778,819	24,845	17,368

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

PROVED
Developed Producing	316,409	273,544
Developed Non-Producing	18,421	15,147
Undeveloped	44,188	38,168
TOTAL PROVED	379,018	326,859

PROBABLE	103,542	88,606

TOTAL PROVED PLUS PROBABLE	482,560	415,465

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

CONSTANT PRICES AND COSTS

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

PROVED
Producing	8,233	5,918	4,710	3,960	3,444
Developed Non-Producing	547	303	207	157	126
Undeveloped	1,328	741	462	304	207
TOTAL PROVED	10,108	6,961	5,378	4,421	3,776

PROBABLE	2,982	1,575	995	697	522

TOTAL PROVED PLUS PROBABLE	13,090	8,536	6,373	5,118	4,298

TOTAL FUTURE NET REVENUE
(UNDISCOUNTED)
as of December 31, 2006
CONSTANT PRICES AND COSTS

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

Proved Reserves	19,795	2,595	6,130	666	296	10,108

Proved Plus Probable Reserves	25,121	3,333	7,411	982	305	13,090

FUTURE NET REVENUE
BY PRODUCTION GROUP
as of December 31, 2006
CONSTANT PRICES AND COSTS

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

Proved Reserves	Light and Medium Crude Oil(1)	3,337
	Heavy Oil(1)	557
	Natural Gas(2)	1,484
TOTAL		5,378

Proved Plus Probable Reserves	Light and Medium Crude Oil(1)	3,910
	Heavy Oil(1)	687
	Natural Gas (2)	1,776
TOTAL		6,373

Notes:

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

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

Reserves Data (Forecast Prices and Costs)

SUMMARY OF OIL AND GAS RESERVES
AND NET PRESENT VALUES OF FUTURE NET REVENUE
as of December 31, 2006
FORECAST PRICES AND COSTS

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

PROVED
Developed Producing	146,914	132,968	40,945	37,366
Developed Non-Producing	6,569	5,970	3,118	2,490
Undeveloped	33,447	29,672	1,839	1,525
TOTAL PROVED	186,929	168,611	45,902	41,381

PROBABLE	50,880	45,152	14,030	12,255
TOTAL PROVED PLUS PROBABLE	237,809	213,763	59,932	53,636

	RESERVES
	NATURAL GAS		NATURAL GAS LIQUIDS
RESERVES CATEGORY	Gross (MMcf)	Net (MMcf)	Gross (Mbbl)	Net (Mbbl)

PROVED
Developed Producing	667,612	546,548	17,093	11,874
Developed Non-Producing	46,580	36,057	1,045	707
Undeveloped	43,433	35,445	1,452	1,009
TOTAL PROVED	757,625	618,049	19,590	13,589

PROBABLE	203,213	167,230	5,303	3,833
TOTAL PROVED PLUS PROBABLE	960,838	785,280	24,893	17,422

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

PROVED
Developed Producing	316,221	273,299
Developed Non-Producing	18,494	15,177
Undeveloped	43,977	38,113
TOTAL PROVED	378,692	326,589

PROBABLE	104,082	89,112
TOTAL PROVED PLUS PROBABLE	482,774	415,701

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

FORECAST PRICES AND COSTS

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

PROVED
Developed Producing	9,369	6,568	5,174	4,333	3,762
Developed Non-Producing	742	375	248	186	149
Undeveloped	1,483	784	475	308	207
TOTAL PROVED	11,593	7,727	5,897	4,826	4,118

PROBABLE	3,847	1,891	1,152	793	588

TOTAL PROVED PLUS PROBABLE	15,440	9,618	7,049	5,619	4,706

TOTAL FUTURE NET REVENUE
(UNDISCOUNTED)
as of December 31, 2006
FORECAST PRICES AND COSTS

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

Proved Reserves	23,611	3,085	7,802	718	412	11,593

Proved Plus Probable Reserves	30,781	4,059	9,762	1,069	451	15,440

FUTURE NET REVENUE
BY PRODUCTION GROUP
as of December 31, 2006
FORECAST PRICES AND COSTS

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

Proved Reserves	Light and Medium Crude Oil (1)	3,319
	Heavy Oil(1)	588
	Natural Gas(2)	1,990
TOTAL		5,897

Proved Plus Probable Reserves	Light and Medium Crude Oil(1)	3,912
	Heavy Oil(1)	731
	Natural Gas(2)	2,406
TOTAL		7,049

Notes:

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

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

Definitions and Notes to Reserves Data Tables

In the tables set forth above in “Disclosure of Reserves Data” and elsewhere in this Annual Information Form the following definitions and other notes are applicable:

1. “Gross” means:

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

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

2. “Net” means:

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

(b) in relation to 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.

3. Columns may not add due to rounding.

4. The crude oil, natural gas liquids and natural gas reserves estimates presented in the GLJ Report are based on the definitions and guidelines contained in the Canadian Oil and Gas Evaluation Handbook (“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, from a given date forward, based on:

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

(b) the use of established technology; and

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

(a) 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.

(b) 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 categorization of reserves are provided in the COGE Handbook.

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

(a) 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.

(b) 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 classification (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 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 will be 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.

5. Forecast prices and costs

These are prices and costs that are generally acceptable as being a reasonable outlook of the future. 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 shall be incorporated into the forecast prices.

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, 2006, inflation and exchange rates utilized in the GLJ Report were as follows:

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

Notes:

(1) Inflation rates for forecasting 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, 2006 were $7.47/Mcf for natural gas, $65.32/bbl for light and medium crude oil, $43.07/bbl for heavy oil and $54.31/bbl for natural gas liquids.

6. Constant prices and costs

These are actual prices and costs as at the effective date of the estimation, held constant throughout the estimated lives of the properties to which the estimate applies. 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 shall be incorporated into the price for future years.

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

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

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

Note:

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

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

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

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

The interest and other costs of 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 anticipate that interest or other funding costs would make development of any property uneconomic.

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

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

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

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

Reconciliations of Changes in Reserves and Future Net Revenue

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

RECONCILIATION OF
NET RESERVES
BY PRINCIPAL PRODUCT TYPE
FORECAST PRICES AND COSTS

	LIGHT AND MEDIUM OIL						HEAVY OIL						NATURAL GAS
FACTORS	Proved (Mbbl)		Probable (Mbbl)		Proved Plus Probable (Mbbl)		Proved (Mbbl)		Probable (Mbbl)		Proved Plus Probable (Mbbl)		Proved (MMcf)		Probable (MMcf)		Proved Plus Probable (MMcf)
December 31, 2005	122,380		25,864		148,244		45,177		11,556		56,733		462,790		109,805		572,595

Extensions	39		15		54		1,795		262		2,057		14,899		2,246		17,145
Improved Recovery(1)	3,106		4,156		7,262		553		248		801		8,767		1,468		10,235
Technical Revisions(2)	(3,268	)	(2,137	)	(5,405	)	(334	)	(49	)	(383	)	(4,901	)	(12,174	)	(17,075	)
Discoveries	—		—		—		—		—		—		1,588		1,946		3,534
Acquisitions	56,751		17,173		73,924		612		234		846		223,120		64,201		287,321
Dispositions	(125	)	(48	)	(173	)	(213	)	(54	)	(267	)	(656	)	(316	)	(978	)
Economic Factors	612		129		741		226		58		284		231		55		286
Production	(10,884	)	—		(10,884	)	(6,435	)	—		(6,435	)	(87,789	)	—		(87,789	)

December 31, 2006	168,611		45,152		213,763		41,381		12,255		53,636		618,049		167,231		785,280

Note:

(1) Improved recovery includes the following infill drilling:

Infill Drilling

1,328

1,377

489

269

758

5,720

720

6,440

	NATURAL GAS LIQUIDS						TOTAL OIL EQUIVALENT
FACTORS	Proved (Mbbl)		Probable (Mbbl)		Proved Plus Probable (Mbbl)		Proved (Mboe)		Probable (Mboe)		Proved Plus Probable (Mboe)

December 31, 2005	9,560		1,990		11,550		254,249		57,711		311,960

Extensions	138		(27	)	111		4,455		624		5,080
Improved Recovery(1)	170		46		216		5,290		4,695		9,985
Technical Revisions(2)	589		(80	)	509		(3,830	)	(4,295	)	(8,124	)
Discoveries	—		1		1		265		325		590
Acquisitions	4,298		1,905		6,203		98,848		30,012		128,859
Dispositions	(6	)	(2	)	(8	)	(453	)	(157	)	(610	)
Economic Factors	5		1		6		881		197		1,078
Production	1,165		—		(1,165	)	(33,116	)	—		(33,116	)

December 31, 2006	13,589		3,834		17,422		326,589		89,113		415,701

Notes:

(1) Improved recovery includes the following infill drilling:

Infill Drilling

131

145

2,901

453

3,354

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

RECONCILIATION OF CHANGES IN
NET PRESENT VALUES OF FUTURE NET REVENUE
DISCOUNTED AT 10% PER YEAR
PROVED RESERVES
CONSTANT PRICES AND COSTS

PERIOD AND FACTOR	2006 (MM$)

Estimated Future Net Revenue at Beginning of Year	4,972

Oil and Gas Sales During Period Net of Production Costs and Royalties(1)	(1,277	)
Changes due to Prices and Royalties Related to Forecast Production(2)	(856	)
Development Costs During the Period(3)	542
Changes in Forecast Development Costs(4)	(544	)
Changes Resulting from Extensions and Improved Recovery(5)	164
Changes Resulting from Discoveries(5)	4
Changes Resulting from Acquisitions of Reserves(5)	1,907
Changes Resulting from Dispositions of Reserves(5)	(7	)
Discount factor(6)	497
Net Change in Income Taxes(7)	—
Changes Resulting from Technical Reserves Revisions	(65	)
All Other Changes(8)	41

Estimated Future Net Revenue at End of Year	5,378

Notes:

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

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

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

(4) The change in forecast future development costs.

(5) End of period net present value of the related reserves.

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

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

(8) Includes changes due to revised production profiles, development timing, operating costs, royalty rates and actual prices received in 2006 versus forecast.

Additional Information Relating to Reserves Data

Undeveloped Reserves

Undeveloped reserves are attributed by GLJ 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 GLJ Report 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). For more information, see “Risk Factors”.

Proved Undeveloped Reserves

GLJ has assigned 44 MMboe of proven undeveloped reserves in the GLJ Report under forecast prices and costs, together with $456 million of associated undiscounted future capital expenditures. Proven undeveloped capital spending in the first

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

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

Penn West holds interests in CO2 injection EOR properties in SE Saskatchewan and Central Alberta, a hydrocarbon injection EOR property in the Swan Hills area, operates a CO2 injection EOR project on the Joffre Viking Tertiary Oil Unit and a hydrocarbon injection EOR project in the South Swan Hills Unit. Development of future miscible and CO2 injection EOR reserves is scheduled over several years in order to maximize the use of existing infrastructure and available injectants.

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

Probable Reserves

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

Significant Factors or Uncertainties

The development schedule of Penn West’s undeveloped reserves is based on forecast and constant 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 — Volatility of Oil and Natural Gas Prices”.

Penn West does not anticipate that any significant economic factors or other significant uncertainties will affect any particular components of its reserves data. However, Penn West’s 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

Overall costs are based on well bore abandonment and reclamation costs and liability issues such as flare pit remediation, and facility decommissioning, remediation, and reclamation costs. These costs were estimated using Penn West’s experience conducting annual abandonment and reclamation programs over the past several years.

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

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

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

Period	Abandonment and Reclamation Costs Escalated at 2% Undiscounted (MM$)	Abandonment and Reclamation Costs Escalated at 2% Discounted at 10% (MM$)
Total liability as at December 31, 2006	1,269	142

Anticipated to be paid in 2007	37	34
Anticipated to be paid in 2008	38	31
Anticipated to be paid in 2009	39	29

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

OTHER OIL AND GAS INFORMATION

Our portfolio of properties as at December 31, 2006 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.

Principal Properties

The following is a description of our principal oil and natural gas properties as at December 31, 2006. Reserve amounts are stated at December 31, 2006, based on escalated cost and price assumptions as evaluated in the GLJ Report prepared by GLJ (see “Statement of Reserves Data”). Information in respect of gross and net acres and well counts is as at December 31, 2006, and information in respect of production is for the year ended December 31, 2006 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, 2006 may not directly correspond to the stated production for the year, which only includes production since the date the interests were acquired by us. In particular, properties producing approximately 40,000 boe/d were acquired under the Petrofund Merger. The production from these properties was recorded effective July 1, 2006. 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.

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

Major Operating Regions

The following table shows Penn West’s reported average daily production and Proved plus Probable Reserves, as at December 31, 2006, by major core region:

	Average Daily Production			Proved Plus Probable Gross Reserves
	Crude Oil and NGLs (bbl/d)	Natural Gas (MMcf/d)	Total (boe/d)	Crude Oil and NGLs (MMbbl)	Natural Gas (Bcf)	Total (MMboe)	Undeveloped Land (000 net acres)
Central	36,916	133	59,142	190.9	450.2	267.1	1,305
Plains	33,640	95	49,412	124.6	221.5	162.8	1,365
Northern	1,934	117	21,456	7.1	289.2	56.0	1,045
Total	72,490	345	130,010	322.6	960.9	485.9	3,715
	56% of daily production	44% of daily production		67% of total reserves	33% of total reserves

Oil and Natural Gas Properties

Penn West’s production and reserves are attributed to more than 400 producing properties. No single property accounts for more than 10 percent of Penn West’s reserves. A general discussion of our operations and activities in each of our core areas follows.

Northern Area

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

The exploration and development of the 100 percent owned Wildboy field followed a Penn West discovery in 1995. Since then, development of the field has continued through the drilling of horizontal and vertical wells, the addition of field booster compression and the subsequent expansion of the plant process and sales line to Alberta to accommodate the increased volumes. Raw throughput of the facility averaged 69 MMcf/d for 2006.

Penn West drilled 33 wells in the Northern Area in 2006, with 2007 plans focusing on additional field compression and wellbore optimization in Wildboy, as well as an extensive 2D and 3D Mississippian seismic program in Wildboy, in preparation for possible drilling in the 2008 season. The Peace River Arch area currently provides approximately four percent of Penn West’s total production. In 2006, Penn West drilled 15 wells in the Firebird area and two at Buick Creek. Plans for 2007 are focused on wellbore optimization at Firebird, Spirit River and Cecil Lake, with current plans for 2008 to drill 18 locations in Firebird. Penn West currently holds approximately 74,000 net acres of undeveloped land in the Peace River Arch area.

Central Area

The Central Area currently provides approximately 39 percent of Penn West’s natural gas production and 51 percent of its liquids production based on 2006 exit rate production. The region contains large, long-life pools of Cardium light oil, oil sands deposits in the Peace River Oil Sands area and shallow to medium-depth, multi-zone natural gas pools. This region is both an established producing area and an area of significant potential reserves and production growth. Penn West’s long-life, low decline rate Cardium oil reserves in the Central Area provide a stable source of premium quality light oil. Cardium oil receives a price very close to the Edmonton par price. Penn West holds approximately 1,305,000 net acres of undeveloped land in the Central Area.

The Central Area is also a significant natural gas producing area, with production of 133 MMcf/d at year-end 2006. The natural gas prospects in the area tend to be multi-zone and relatively liquids rich. Penn West’s control of several natural gas processing facilities throughout the area allows Penn West to gain economies of scale in the surrounding natural gas operations. One of our principal facilities in the Central Area is the Minnehik-Buck Lake natural gas processing facility in which Penn West controls a majority interest. The facility has the capacity to process over 120 MMcf/d of natural gas including the capability to process sour natural gas.

Central — Peace River Oil Sands

Since 2002, Penn West has grown its land base to approximately 300,000 net acres of 100 percent owned oil sands leases in the Peace River oil sands area. As of the end of 2006, we have drilled 54 horizontal wells and seven stratigraphic wells in the focus areas of Seal Main, Seal North and Cadotte. In 2006, Penn West acquired a 35 percent working interest in a 13,500 bbl/d facility and a 15 percent working interest in a 55,000 bbl/d pipeline. In 2007, 30 stratigraphic wells and 80 to 90 net horizontal wells are planned, with capital programs of approximately $175 million, excluding acquisitions. Penn West currently estimates the project area contains 6.8 billion barrels of heavy oil resources in place. This estimate represents the mid case. Using the definitions set out in the COGE Handbook, these resources are considered “Discovered Resources”. As Penn West is in the early stages of the project, these resources have not been classified into more specific categories. There is no certainty that a significant portion of these resources will be recovered or that a significant portion of the resources will be economically or technically feasible to produce in the future. Discovered resources are those quantities of oil and gas estimated on a given date to be remaining in, plus those quantities already produced from, known accumulations. Discovered

resources consist of economic and uneconomic resources with the estimated future recoverable portion classified as reserves or contingent resources.

Central-Pembina

Pembina produces high-netback, long-life, low-decline light oil and liquids-rich natural gas. Approximately 1,150 operated producing wellbores account for 14,400 bbl/d or 11 percent of our 2006 production. The Petrofund Merger further consolidated Penn West’s land position in the area, lifting our average working interest to approximately 87 percent and increasing overall operated volumes by about 20 percent or approximately 2,900 boe/d. Our share of current Pembina area production is approximately 18,900 boe/d including operated and non-operated volumes.

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

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

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

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

Central - Willesden Green

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

Willesden Green is an active development area. The 17 development and exploitation wells planned in 2007 (up from 10 wells in 2006) are intended to fully offset natural production declines. We retain deep mineral rights throughout the area, enhancing longer-term exploration potential for Penn West or drilling partners.

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

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

Central — Swan Hills

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

The South Swan Hills Unit is also the site of two new pilot projects: The Mannville horizontal coal bed methane (“CBM”) project, which is currently beginning production operations and the Swan Hills CO2 pilot, which is scheduled to begin construction later in 2007.

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

Trident/Nexen’s Corbett Creek CBM property, the dewatering process could take between six and 12 months for the initial pilot wells, shortening as development takes place and the coals are de-pressured. Pending the success of the pilot project, full-scale CBM development could take place over the next four years.

The planned CO2 pilot in South Swan Hills will target portions of the Swan Hills reef complex that have not been efficiently miscible flooded in the past. This pilot will also help in the evaluation of the potential of using CO2 flooding in the East Swan Hills Unit, which has not undergone any miscible flooding to date, but is geologically similar to the CO2 pilot area.

The Petrofund Merger in 2006 also resulted in new or increased working interests in the Swan Hills Unit #1, House Mountain Unit, Mitsue Unit, and the Kaybob Unit. Additional working interests were acquired in the Otter and Red Earth areas with new production in the Loon and Ogston areas also acquired.

Plains Area

The Plains Area is a shallow depth region with multi-zone potential that supplies 28 percent of Penn West’s natural gas production and 46 percent of the liquids based on 2006 exit rate production. In 2006, Penn West drilled 148 net wells in this area. Target zones include the Bakken, Mannville and Viking. Extensive 2D and 3D seismic is used to select drilling locations. Penn West owns and operates an extensive infrastructure of gas plants, batteries and pipelines in the Plains Area. In 2007, Penn West plans to drill 95 net wells and holds approximately 1,365,000 net acres of undeveloped land in the area.

Plains — Wainright

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

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

Plains — Hoosier — Coleville

Hoosier and Coleville consist of more than 20 producing properties around Hoosier and form one of Penn West’s most active development areas. These mostly Penn West operated assets include approximately 4,210 producing wellbores, a high average working interest of over 95 percent, extensive Penn West infrastructure and a combined 918,000 acres of lands, of which 396,000 net acres are undeveloped. The Petrofund Merger added geographically and technically complementary properties to the Hoosier group, increasing the area’s production by 10 percent.

Hoosier’s primary commodity is cold-pumped conventional heavy oil. The main geological targets are the seismically defined Mannville Group, Bakken and geographically vast Viking horizons, all at depths shallower than 850 metres. Penn West drilled 97 wells throughout Hoosier in 2006, including 34 vertical wells, 16 horizontal wells and 47 natural gas wells. The program added 1,550 bbl/d of crude oil and four MMcf/d of natural gas with additional new capacity “behind pipe” to be tied in during 2007.

In 2007, Penn West has budgeted $47 million to drill 51 vertical wells and eight horizontal wells in Hoosier. The main focus will be oil development driven by the scope of medium-term opportunities rather than short-term price volatility.

Plains — South and Other Area

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

We acquired a 21.1 percent interest in the Weyburn Unit located in Southeast Saskatchewan in the Petrofund Merger. Weyburn is Canada’s largest commercial CO2 enhanced oil recovery project, producing approximately 30,000 bbl/d (approximately 6,300 bbl/d net to us) at December 31, 2006, sourcing CO2 for injection from a coal gasification plant in North Dakota. Our share of capital costs was $43.2 million in 2006 increasing to approximately $44.8 million in 2007 due to

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

Additional Information

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

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

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, 2006.

	Producing				Non-Producing		Total
	Oil		Gas
	Gross	Net	Gross	Net	Gross	Net	Gross	Net
Alberta	6,122	4,065	3,280	2,117	4,135	2,837	13,537	9,019
British Columbia	48	20	468	304	200	136	716	460
Saskatchewan	3,640	3,019	661	536	1,713	1,344	6,014	4,899
Manitoba	137	129	—	—	76	71	213	200
Total	9,947	7,233	4,409	2,957	6,124	4,388	20,480	14,578

Undeveloped Land Holdings

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

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

We currently have no material work commitments on these lands. The primary lease or extension term on 1,030,000 net acres will expire by December 31, 2007. 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 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. If the proposed changes to the taxation of income trusts are enacted, taxes could be exigible in the Trust as certain distributions would no longer be a deduction in the calculation of its taxable income. For more information on these proposals, see “Description of Our Business — Proposed Federal Tax Changes” and “Risk Factors — Proposed Federal Tax 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, 2006:

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

Notes:

(1) Costs of land acquired, geological and geophysical capital expenditures and drilling costs for 2006 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, 2006:

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

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

Production Estimates

The following table sets out the volume of our production estimated for the year ended December 31, 2007 which is reflected in the estimate of future net revenue disclosed in the tables contained under “Statement of Reserves Data - Disclosure of Reserves Data”.

	Light and Medium Oil		Heavy Oil		Natural Gas		Natural Gas Liquids		Total
	(bbl/d)		(bbl/d)		(Mcf/d)		(bbl/d)		(Boe/d)
	Gross	Net	Gross	Net	Gross	Net	Gross	Net	Gross	Net
Proved Producing	39,000	34,168	19,749	17,544	295,371	233,485	5,962	4,164	113,939	94,789
Proved Developed Non-Producing	616	500	407	340	13,888	10,546	213	148	3,551	2,746
Proved Undeveloped	1,323	1,042	382	293	1,672	1,305	72	52	2,056	1,604
Total Proved	40,939	35,710	20,538	18,177	310,931	245,336	6,247	4,364	119,546	99,139
Total Probable	807	563	893	171	16,561	12,401	197	140	4,656	3,487
Total Proved PlusProbable	41,746	36,273	21,431	18,894	327,492	257,737	6,444	4,504	124,202	102,626

Production History

The following tables summarize certain information in respect of our production, product prices received, royalties paid, operating expenses and resulting netback for the periods indicated below:

	Quarter Ended 2006				Year Ended
	Mar. 31	June 30	Sept. 30	Dec. 31	Dec. 31, 2006
Average Daily Production(1)
Light and Medium Crude Oil (bbl/d)	27,441	26,646	42,150	42,898	34,847
Heavy Oil (bbl/d)	20,685	18,625	21,186	22,586	20,776
Gas (MMcf/d)	266.9	267.9	359.1	354.6	312.5
NGLs (bbl/d)	4,100	3,331	5,879	5,335	4,668
Combined (boe/d)	96,713	93,242	129,059	129,915	112,369

Average Net Production Prices Received
Light and Medium Crude Oil ($/bbl)	63.42	73.20	72.27	58.51	66.46
Heavy Oil ($/bbl)	30.76	52.85	52.20	37.57	43.07
Gas ($/Mcf)	8.12	6.14	5.97	6.97	6.75
NGLs ($/bbl)	53.19	62.08	55.75	48.76	54.31
Combined ($/boe)	49.23	51.33	51.33	46.88	49.58

Royalties Paid
Light and Medium Crude Oil ($/bbl)	9.36	8.83	10.40	9.38	9.58
Heavy Oil ($/bbl)	4.85	8.50	7.50	5.44	6.51
Gas ($/Mcf)	1.78	1.43	1.28	1.61	1.51
NGLs ($/bbl)	17.58	21.05	15.87	16.91	17.46
Combined ($/boe)	9.36	9.09	8.90	9.12	9.10

Operating Expenses (2)(3)
Light and Medium Crude Oil ($/bbl)	15.64	16.38	16.57	15.53	16.03
Heavy Oil ($/bbl)	10.55	11.49	10.93	11.88	11.22
Gas ($/Mcf)	0.94	0.97	1.00	1.04	0.99
NGLs ($/bbl)	13.87	13.85	14.43	13.98	14.09
Combined ($/boe)	9.88	10.26	10.64	10.61	10.39

Transportation
Light and Medium Crude Oil ($/bbl)	—	—	—	—	—
Heavy Oil ($/bbl)	0.15	—	0.07	0.07	0.07
Gas ($/Mcf)	0.23	0.21	0.23	0.18	0.21
NGLs ($/bbl)	—	—	—	—	—
Combined ($/boe)	0.66	0.60	0.64	0.51	0.60

(Gain)/Loss on Risk Management Contracts
Light and Medium Crude Oil ($/bbl)	—	2.37	2.24	0.01	1.14
Heavy Oil ($/bbl)	—	—	—	—	—
Gas ($/Mcf)	(0.22)	(0.93)	(1.07)	(0.56)	(0.72)
NGLs ($/bbl)	—	—	—	—	—
Combined ($/boe)	(0.62)	(2.00)	(2.23)	(1.53)	(1.64)

Netback Received(4)
Light and Medium Crude Oil ($/bbl)	38.41	45.60	43.05	33.58	39.70
Heavy Oil ($/bbl)	15.21	32.86	33.70	20.18	25.27
Gas ($/Mcf)	5.39	4.46	4.53	4.70	4.76
NGLs ($/bbl)	21.74	27.18	25.40	17.87	22.75
Combined ($/boe)	29.95	33.38	33.38	28.17	31.13

Notes:

(1) Before deduction of royalties.

(2) Operating expenses are composed of 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 and losses/gains on commodity and foreign exchange contracts from revenues.

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

Marketing and Future Commitments

Our marketing approach continues to reflect the following principles:

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

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

· Optimize netbacks on crude oil production through blending, trucking and proprietary handling of emulsion.

Natural Gas Marketing

In 2006, Penn West received an average price from the sale of natural gas, including hedging gains, of $7.47/Mcf compared to $8.74/Mcf realized in 2005. Approximately 85 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 five percent of sales.

Oil and Liquids Marketing

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

We market our production at the lease level on varying term contracts that capture premiums on postings for the majority of corporate sales 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 and conventional heavy oil for the periods indicated:

	2006		2005
	Light and Medium Oil	Heavy Oil	Light and Medium Oil	Heavy Oil
Quarter ended	($/bbl)	($/bbl)	($/bbl)	($/bbl)
March 31	63.42	30.76	57.62	28.06
June 30	73.20	52.85	61.01	31.22
September 30	72.27	52.20	73.76	48.60
December 31	58.51	37.57	64.56	34.95

Forward Contracts

Our Board of Directors approved a policy that enables us to hedge up to 50 percent of our liquids and natural gas price exposure (net of royalties) for a maximum of two years and up to 75 percent for a maximum of one year. As at December 31, 2006 Penn West was not bound by any agreement (including a transportation agreement), directly or through an aggregator, under which it may be precluded from fully realizing, or from being protected from the full effect of, future market prices for oil or natural gas except for the following financial hedging positions that were outstanding as at December 31, 2006:

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

Note:

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

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.

Future Commitments

We have committed to certain payments over the next five years, in addition to regular payments under our credit facilities, as follows:

($ millions)	2007	2008	2009	2010	2011	Thereafter
Transportation	20.0	9.2	4.7	1.9	—	—
Transportation ($US)	2.5	2.3	2.3	2.3	2.3	8.6
Power Infrastructure	4.6	3.7	3.7	3.7	3.7	7.6
Drilling Rigs	6.9	7.7	2.4	1.2	—	—
Purchase Obligations(1)	13.2	13.3	13.3	13.3	13.3	54.3
Office Lease	12.0	17.9	17.5	15.1	14.3	117.5

Note:

(1) These amounts represent estimated commitments of $95.5 million for CO2 purchases and $25.2 million for processing fees related to interests in the Weyburn unit.

Environmental Matters

The oil and natural gas industry is subject to environmental regulations under provincial and federal legislation. Environmental regulations impose, among other things, restrictions, liabilities and obligations in connection with the generation, handling, storage, transportation, treatment and disposal of hazardous substances and waste and in connection with spills, releases and emissions of various substances to the environment. Environmental legislation also requires that wells, facility sites and other properties associated with our operations be operated, maintained, abandoned and reclaimed to the satisfaction of applicable regulatory authorities. In addition, certain types of operations, including exploration and development projects and significant changes to certain existing projects, may require the submission and approval of environmental impact assessments or permit applications. Compliance with this legislation can require significant expenditures; a breach of such requirements could result in the imposition of material fines and facility closures. Penn West’s environmental programs are monitored to ensure that they comply with all government environmental regulations and with Penn West’s own environmental policies. The results of these programs are reviewed with Penn West’s management and operations personnel.

In December 2002, the Government of Canada ratified the Kyoto Protocol that became legally binding on February 16, 2005. This protocol calls for Canada to reduce its greenhouse gas emissions to six percent below 1990 levels during the period between 2008 and 2012. Details of specific requirements relating to the oil and gas industry have not been enacted and accordingly the impact of the Kyoto Protocol is unknown.

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 Penn West Petroleum Ltd. may authorize the creation and issuance of debentures, notes and other evidences of indebtedness by us 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 our auditors and to elect all the members of the Board of Directors.

Our Management

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

Penn West Petroleum Ltd. 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 our 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 that we maintain our status as a “mutual fund trust” under the Income Tax Act (Canada), certain provisions of the Income Tax Act (Canada) require that we not be established nor maintained primarily for the benefit of non-residents of Canada (“non-residents”). The Trust Indenture provides that the Trust will use its best commercial efforts to maintain its status as a mutual fund trust under the Income Tax Act (Canada). See “Risk Factors — Non-Resident Ownership of Trust Units”.

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 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 Penn West Petroleum Ltd. 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 directors of Penn West Petroleum Ltd. 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 Notes.

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 and registered education savings plans.

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

Reporting to Unitholders

Our 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. Our 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, Penn West Petroleum Ltd. has been delegated responsibility for substantially all of the management decisions of the Trust. The Unitholders are entitled to elect all of the Board of Directors pursuant to the terms of the Trust Indenture.

Trust Indenture

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

Petroleum Ltd. who shall be the same as our auditors. Prior to us voting our common shares in Penn West Petroleum Ltd., 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 we are required to vote our common shares in Penn West Petroleum Ltd. in accordance with the result of the vote of Unitholders.

Decision Making

The Board of Directors has a mandate to supervise the management of our business and affairs, Penn West Petroleum Ltd. and our other direct or indirect subsidiaries and partnerships and to act with a view to our 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 Penn West Petroleum Ltd.’s articles to create exchangeable shares. The Board of Directors holds regularly scheduled meetings at least quarterly to review the business and affairs of our subsidiaries, partnerships and trusts 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 our behalf reviews the distribution policy from time to time. The actual amount distributed will be dependent on various factors including the commodity price environment and is at the discretion of the Board of Directors of Penn West. The current distribution policy targets the use of approximately 60 percent to 70 percent of cash 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 cash flow will fund all or a portion of the Trust’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.

Pursuant to the provisions of the Trust Indenture all taxable income earned by the Trust in a fiscal year, not previously distributed in that fiscal year, must be distributed to Unitholders of record on December 31. 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 Toronto Stock Exchange. 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.

Directors and Officers

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

Directors

Name and Municipality of Residence	Director Since	Principal Occupation

James E. Allard(1) Calgary, Alberta, Canada	2006	Independent director and business advisor

William E. Andrew Calgary, Alberta, Canada	1994	President and Chief Executive Officer Penn West Petroleum Ltd.

George H. Brookman(1)(4)(5) Calgary, Alberta, Canada	2005	President and Chief Executive Officer of West Canadian Industries Group Inc.

John A. Brussa Calgary, Alberta, Canada	1995	Partner, Burnet, Duckworth & Palmer LLP (barristers and solicitors).

Jeffery E. Errico(3)(5) Calgary, Alberta, Canada	2006	Executive Chairman of Insignia Energy Inc., a private oil and natural gas company.

Murray R. Nunns(1)(2)(3)(5) Calgary, Alberta, Canada	2005	Executive Chairman of Monterey Exploration Ltd.

Thomas E. Phillips(1)(2)(3)(4)(5) Calgary, Alberta, Canada	1995	President, Newhaven Investments Inc. (oil and gas company).

Frank Potter(2)(4) Toronto, Ontario, Canada	2006	Chairman of Emerging Markets Advisors, Inc. (investment consulting firm)

James C. Smith(1)(3)(4)(5) Calgary, Alberta, Canada	2005	Independent director.

Notes:

(1) Member of audit committee.

(2) Member of human resources and compensation committee.

(3) Member of reserves committee.

(4) Member of the governance committee.

(5) Member of the health, safety and environment committee.

All of the directors have held the principal occupation set forth beside their name for the last five years except for the following: Murray R. Nunns, from 2002 to 2005, was President, Chief Executive Officer and Director of Crispin Energy Inc. and prior thereto held various management positions at Rio Alto Exploration Ltd. including Chief Operating Officer. Jeffery E. Errico was President and CEO of Petrofund Energy Trust since 2003 and President of Petrofund Energy Trust prior thereto, and James C. Smith who was also Chief Financial Officer of Mercury Energy Corporation, a private oil and natural gas company, from 2002 to 2006.

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

Executive Officers

Name and Municipality of Residence		Office and Principal Occupation

William Andrew Calgary, Alberta, Canada		President and Chief Executive Officer

David Middleton Calgary, Alberta, Canada		Executive Vice President and Chief Operating Officer

Thane Jensen Calgary, Alberta, Canada		Senior Vice President, Exploration and Development

Todd Takeyasu Calgary, Alberta, Canada		Senior Vice President and Chief Financial Officer

William Tang Kong Calgary, Alberta, Canada		Senior Vice President, Corporate Development

Anne Thomson Calgary, Alberta, Canada		Vice President, Exploration

Eric Obreiter Calgary, Alberta, Canada		Vice President, Production

Gregg Gegunde Calgary, Alberta, Canada		Vice President, Development

Kristian Tange Calgary, Alberta, Canada		Vice President, Business Development

Lucas Law Calgary, Alberta, Canada		Vice-President, Asset Management

Keith Luft Calgary, Alberta, Canada		Vice-President, Land and Legal

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

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

Corporate Cease Trade Orders or Bankruptcies

Except as otherwise disclosed herein, in the ten years preceding the date of this Annual Information Form, none of the proposed directors, officers or insiders of Penn West Petroleum Ltd. are or have been a director, officer or promoter of any other issuer that, while acting in such capacity:

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

(b) was declared bankrupt or made a voluntary assignment in bankruptcy, made a proposal under any legislation relating to bankruptcy and insolvency or been 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 that person’s stock.

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. (now Rider Resources Ltd.), both of which trade on the Toronto Stock Exchange.

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 Toronto Stock Exchange. 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.

Penalties or Sanctions

None of the proposed directors, officers or insiders of Penn West Petroleum Ltd. have been subject to any penalties or sanctions under securities legislations except as disclosed herein.

Personal Bankruptcies

None of the directors, officers or insiders of Penn West Petroleum Ltd. have in the ten years preceding the date of this Annual Information Form become bankrupt, made a proposal under any legislation relating to bankruptcy or insolvency, or been subject to or instituted any proceedings, arrangement or compromise with creditors or had a receiver, receiver manager or trustee appointed to hold their assets except as disclosed herein.

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 and 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 President and 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 the Trust.

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 the Trust. Passive investments in public or private entities of less than one per cent of the outstanding shares will not be viewed as “competing” with the Trust. No executive officer or employee of Penn West 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 Penn West 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 the Trust, the Board of Directors will take such actions as are reasonably required to resolve such matters with a view to the best interests of the Trust. Such actions, without limitation, may include excluding such directors, officers or employees from certain information or activities of the Trust.

The Business Corporations Act (Alberta) 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.

AUDIT COMMITTEE DISCLOSURES

Multilateral Instrument 52-110 (“MI 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 C to this Annual Information Form.

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

James C. Smith (Chairman)

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

company and from 2001 until the sale of the company in 2003, was the Chief Financial Officer of Segue Energy Corporation, a private oil and natural gas company. 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. While Mr. Smith was the Vice President and Chief Financial Officer of Crestar Energy Inc. from its inception in 1992 until 1998, the company completed an initial public offering, was listed on the Toronto Stock Exchange and completed several major debt and equity financing transactions. Mr. Smith is currently a director of Grand Petroleum Inc., TAG Oil Ltd., Pure Energy Services Inc., and Grey Wolf Exploration Inc.

James E. Allard

Mr. Allard received his 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 serving as CEO, CFO and a director of a number of publicly traded and private companies. During the past seven years he served on the board of the Alberta Securities Commission, acting as the sole external trustee and advisor to a mid-sized pension plan and serves as a director and advisor to several companies. From 1981 to 1995, he served as a senior executive officer of Amoco Corporation as well as a director of Amoco Canada, then Canada’s largest natural gas producer.

George H. Brookman

Mr. Brookman acquired West Canadian Industries Group in 1984 and under his leadership it has become one of Canada’s largest privately held digital printing and imaging service companies.

He is also a partner in Vistek, a major retail camera operation with stores in Toronto, Calgary and one under construction in Edmonton and was the founder of Commonwealth Legal Inc., Canada’s only national litigation support services operating in six Canadian cities. Prior to acquiring West Canadian Industries Group, Mr. Brookman was involved for many years in the commercial development industry in the Real Estate Group of Manulife and later as the Vice President of ATCO Development Ltd.

In addition to his thirty-five years of business experience, Mr. Brookman has been active in the community and is currently the Chairman elect of the Calgary Exhibition and Stampede. He is also on the advisory Board of the Department of Communications and Culture of the University of Calgary, a Director of KSPS Television in Spokane, Washington and Past President of the Rotary Club of Calgary.

Murray R. Nunns

Mr. Nunns is currently the Executive Chairman of Monterey Exploration Ltd. and is also a director of several other oil and gas companies in Western Canada including Capital Energy Ltd. and three additional private junior oil and natural gas companies. Mr. Nunns has over 25 years of experience with domestic and international oil and natural gas exploration and production activities. From 2003 to 2005, Mr. Nunns served as President, CEO and Director of Crispin Energy Inc. and from 1993 to 2002, held a variety of management positions at Rio Alto Exploration Ltd. including Executive Vice President of Exploration and Development and Chief Operating Officer. From 1986 to 1993, Mr. Nunns worked in several capacities with Unocal Exploration Ltd. including Chief Geologist for Unocal Canada and in portfolio management of its international exploration program. Mr. Nunns is a graduate of the University of Toronto and holds a Bachelor of Science (Honours) in Geology.

Thomas E. Phillips

Mr. Phillips is the President of Newhaven Investments Inc., a private company engaged in the acquisition, drilling and production of oil and natural gas in Alberta, and land development on the Sunshine Coast of British Columbia. He studied mathematics at the University of British Columbia and in 1976 received his Bachelor of Science degree from the University of Calgary with a major in geology and minor in computer science. He has worked at several companies including Home Oil, Placid Oil, and Placer CEGO and served as President of Albany Oil & Gas and Northern Reef Exploration Ltd. Mr. Phillips has been a Director of Penn West since 1995.

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.

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

Audit Fees

The aggregate fees billed by our external auditor for audit services were:

2006	—	$485,000

2005	—	$215,000

Audit Related Fees

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

2006	—	$230,000

2005	—	$187,500

Tax Fees

The aggregate fees billed by our external auditor for professional services for tax compliance, tax advice and tax planning were:

2006	—	$18,341

2005	—	$42,738

All Other Fees

The aggregate fees billed by our external auditor for products and services not included under the headings Audit Fees, Audit Related Fees and Tax Fees were:

2006	—	$NIL

2005	—	$NIL

DISTRIBUTIONS TO UNITHOLDERS

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

For the Month Ended	Distributions per Unit

	2006		2005
January	$	0.31	N/A
February	0.34		N/A
March	0.34		N/A
April	0.34		N/A
May	0.34		N/A
June	0.34		$	0.26
July	0.34		0.26
August	0.34		0.26
September	0.34		0.26
October	0.34		0.31
November	0.34		0.31
December	0.34		0.31
Total	$	4.05	$	1.97

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

MARKET FOR SECURITIES

The Trust Units are listed and traded on the Toronto Stock Exchange (“TSX”) under the symbol PWT.UN and on the New York Stock Exchange (“NYSE”) under the symbol PWE. The following tables set forth trading information for our Trust Units in 2006.

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

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

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

June(1)	40.20	37.20	1,907,200
July	41.09	37.40	7,733,100
August	42.98	40.02	10,105,100
September	41.46	35.39	14,942,300
October	39.38	31.50	13,124,000
November	34.00	27.74	39,446,400
December	32.72	30.35	15,114,700

Note:

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

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 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 exports for a term of less than two years or for a term of two years 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 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 and limit the ability to produce and to market natural gas production. In addition, the pro-rationing of capacity on the inter-provincial pipeline systems 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, 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 which 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 negotiations between the mineral owner and the lessee, although production from such lands is also 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 has been for provincial governments to eliminate, amend or allow such incentive programs to expire without renewal, and consequently few such incentive programs are currently operative.

The Canadian federal corporate income tax rate levied on taxable income is 22.1 percent effective January 1, 2007 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 2006 Federal Budget, the federal corporate income tax rate will decrease to 19 percent in three steps: 20.5 percent on January 1, 2008; 20 percent on January 1, 2009 and 19 percent on January 1, 2010.

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. Currently, the amount of royalties that are payable is influenced by the oil production, density of the oil, and the vintage of the oil. Originally, the vintage classified oil in “new oil” and “old oil” depending on when the oil pools were discovered. If discovered prior to March 31, 1974 is considered “old oil”, if discovered after March 31, 1974 and before September 1, 1992, is considered “new oil”. The Alberta government introduced in 1992 a Third Tier Royalty with a base rate of 10 percent and a rate cap of 25 percent for oil pools discovered after September 1, 1992. The new oil royalty reserved to the Crown has a base rate of 10 percent and a rate cap of 30 percent. The old oil royalty reserved to the Crown has a base rate of 10 percent and a rate cap of 35 percent.

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

Oil sands projects are subject to a specific regulation made effective July 1, 1997, and expiring June 30, 2007, which, among other things, determines the Crown’s share of crude and processed oil sands products.

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 (“ARTC”) was to be eliminated, effective January 1, 2007. The programs affected by this announcement are: (i) Deep Gas Royalty Holiday; (ii) Low Productivity Well Royalty Reduction; (iii) Reactivated Well Royalty Exemption; and (iv) Horizontal Re-Entry Royalty Reduction. The program being introduced is the Innovative Energy Technologies Program (the “IETP”) which is intended to

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

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

British Columbia

Producers of oil and natural gas in the Province of 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 11,450 m3 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 would 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 then the royalty payable on non-conservation gas.

On May 30, 2003, the Ministry of Energy and Mines for the Province of 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 will result in economic and employment opportunities for communities in British Columbia’s heartlands.

Some of the financial incentives in the Strategy include:

· Royalty credits of up to $30 million annually 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.

· 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.

On February 27, 2007 the Government of British Columbia unveiled the Energy Plan outlining the Province’s strategy towards the environment and which includes targeting for zero net greenhouse gas emissions, promoting new investments in innovation, and becoming the world’s leader in sustainable environmental management. With regards to the oil and gas industry, the objective is to achieve clean energy through conservation and energy efficient practices, whilst competitiveness is advocated in order to attract investment for the development of the oil and gas sector. Among the changes to be implemented are: (i) a new of Net Profit Royalty Program; (ii) the creation of a Petroleum Registry; (iii) the establishing 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) new the 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.

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 (“fourth-tier oil” introduced October 1, 2002, “third-tier oil”, “new oil”, or “old oil”) of oil production are applicable to each of the three crude oil types. The Crown royalty and freehold production tax structure for crude oil is price sensitive and varies between the base royalty rates of 5 percent for all “fourth-tier oil” to 20 percent for “old oil”. Marginal royalty rates are 30 percent for all “fourth-tier oil” to 45 percent 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 percent for “fourth-tier gas” and 20 percent for “old gas”. The marginal royalty rates are between 30 percent for “fourth -tier gas” and 45 percent 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. The royalty/tax will be payable on associated natural gas produced from an oil well that exceeds approximately 65 thousand cubic metres in a month.

· 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 percent 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.

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 five years since the Government of Canada had the initiative to reintroduce the full deduction of provincial resource royalties from federal and provincial taxable income.

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 currently subject to environmental regulations pursuant to a variety of provincial and federal legislation. Environmental regulations impose, among other things, restrictions, liabilities and obligations in connection with the generation, handling, storage, transportation, treatment and disposal of hazardous substances and waste and in connection with spills, releases and emissions of various substances to the environment. Environmental legislation

also requires that wells, facility sites and other properties associated with our operations be operated, maintained, abandoned and reclaimed to the satisfaction of applicable regulatory authorities. In addition, certain types of operations, including exploration and development projects and significant changes to certain existing projects, may require the submission and approval of environmental impact assessments or permit applications. 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.

Environmental legislation in the Province of 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. No additional expenses are foreseen that are associated with complying with the new regulations. 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, and will be taking such steps as required to ensure compliance with the EPEA and similar legislation in other jurisdictions in which it operates. We believe that we will be 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.

British Columbia’s Environmental Assessment Act became effective 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.

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

The Government of Canada has announced its intention to regulate greenhouse gases (“GHG”) and other air pollutants. The Government is currently developing a framework that outlines its clean air and climate change action plan, including a target to reduce GHG emissions by 45 percent to 65 percent by 2050 and a commitment to regulate industry on an emissions intensity basis in the short-term. Currently there are few technical details regarding the implementation of the Government’s plan to regulate industrial GHG emissions, but the Government has made a commitment to work with industry to develop the specifics.

The Alberta Government has also released draft regulations that will require facilities that emit over 100,000 tonnes of CO2E/yr (total Greenhouse Gases in terms of CO2 equivalent) to reduce their emissions intensity (quantity of gases releases per unit of production) by 12 percent starting July 1, 2007. Facilities that do not reduce their emissions intensity by this amount will either be charged $15/tonne for every tonne they are over the 12 percent target or they will have to invest in projects outside of their facility, but still in Alberta, that reduce or offset emissions on their behalf. Penn West currently does not operate any facilities that fall under the current regulations but it does have a working interest in some facilities that do. The full impact of this regulation is currently unknown but it is very likely that these targets will result in increased operating costs for facilities that are under these regulations. However, Penn West believes that this new regulation will be of overall benefit to the Trust as it will most likely result in increased interest in CO2 capture and storage technologies and infrastructure that will increase the speed of development of its CO2 injection plans in Pembina.

As the federal and provincial programs are under development, Penn West is unable to predict the total impact of the potential regulations upon its business. Therefore, it is possible that we could face increases in operating costs in order to comply with GHG emissions legislation. However, Penn West in cooperation with the Canadian Association of Petroleum Producers will continue to work with the Government 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 its current activities to reduce emissions intensity, improve energy efficiency and develop CO2 injection and sequestration infrastructure. See “Risk Factors — Environmental” and “Risk Factors — Kyoto Protocol”.

RISK FACTORS

The following is a summary of certain risk factors relating to our business which prospective investors should carefully consider before deciding whether to purchase Trust Units.

Volatility of Oil and Natural Gas Prices

Our operational results and financial condition of our operating entities and therefore the amounts paid to us will be dependent on the prices received for oil and natural gas production. Oil and natural gas prices have fluctuated widely during recent years and are determined by economic, and in the case of oil prices, also political factors. Supply and demand factors, including weather and general economic conditions, as well as conditions in other oil and natural gas regions impact prices. Any movement in oil and natural gas prices will have an effect on our cash flow from operations, financial condition and therefore on our financial position and the cash available to be distributed to Unitholders. 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 were to increase. In addition, commodity hedging activities could expose us to cash and income losses. To the extent that we engage in risk management activities related to commodity prices, there are credit risks associated with counterparties with which we contract.

Variations in Foreign Exchange Rates and Interest Rates

World oil prices are quoted in United States dollars and the price received by Canadian producers is therefore affected by the Canadian/U.S. dollar exchange rate that may fluctuate over time. A material increase in the value of the Canadian dollar may negatively impact our operating entities production revenues. The increase in the exchange rate for the Canadian dollar and future Canadian/United States exchange rates could accordingly impact future distributions and the future value of our reserves as determined by independent evaluators.

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

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, as well as negatively impact the market price of the Trust Units.

Proposed Federal Tax Changes

On October 31, 2006 the Federal Minister of Finance proposed to apply a tax at the trust level on distributions of certain income from publicly traded mutual fund trusts at rates of tax comparable to the combined federal and provincial corporate tax and to treat such distributions as dividends to the unitholders (the “October 31 Proposals”). On December 21, 2006 the Federal Minister of Finance released draft legislation to implement the October 31, 2006 Proposals pursuant to which, commencing January 1, 2011 (provided Penn West only experiences “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 the Unitholders and will be subject to tax at the corporate rates at the Trust level. Assuming the October 31 Proposals are ultimately enacted in their current form, the implementation of such legislation would be 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.

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

Further, the proposals provide that, while there is no intention to prevent “normal growth” during the transitional period, any “undue expansion” could result in the transition period being “revisited”, presumably with the loss of the benefit to us of that transitional period. As a result, the adverse tax consequences resulting from the proposals 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” (“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 are 40 percent for the period from November 1, 2006 to December 31, 2007, and 20 percent 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:

(a) 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);

(b) 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; and

(c) the exchange, for trust units, of exchangeable partnership units or exchangeable shares that were outstanding on October 31, 2006 will not be considered growth for those purposes and will therefore not affect the safe harbour where the issuance of the trust units is made in satisfaction of the exercise of the exchange right by a person other than the SIFT.

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

While these guidelines are such that it is unlikely they would affect our ability to raise the capital required to maintain and grow our existing operations in the ordinary course during the transition period, they could adversely affect the cost of raising capital and our ability to undertake more significant acquisitions.

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

Reserve Estimates

There are numerous uncertainties inherent in estimating quantities of oil, natural gas and NGLs reserves and cash flows to be derived therefrom, including many factors beyond our control. The reserve and associated cash flow information set forth in this Annual Information Form represents estimates only. In general, estimates of economically recoverable oil and natural gas reserves and the future net cash 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. All such estimates are to some degree speculative, and classifications of reserves are attempts to define the degree of speculation involved. For those reasons, estimates of the economically recoverable oil and natural gas reserves 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 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 has used both constant and forecast price and cost estimates in calculating reserve quantities included in this Annual Information Form. Actual future net cash 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 cash flows derived from reserves will vary from the reserves estimates contained in the engineering reports summarized in this Annual Information Form, and such variations could be material. The GLJ Report is based in part on the assumed success of activities we intend to undertake in future years. The reserves and estimated cash flows to be derived therefrom contained in the engineering reports summarized in this Annual Information Form will be reduced, in future years, to the extent that such activities do not achieve the level of success assumed in the engineering reports summarized in this Annual Information Form.

Depletion of Reserves

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 cash flow to Unitholders, we will not be reinvesting cash flow in the same manner as some other industry participants and will only conduct limited exploratory activities as one of our main objectives is to maximize long-term distributions. Accordingly, absent capital injections, our initial production levels and reserves will decline over time and, absent changes to other factors, the level of income available for distributions will also decline over time.

Our future oil and natural gas reserves and production, and therefore our cash flows, will be highly dependent on our success in exploring and exploiting our reserve 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 produced.

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 will be impaired. To the extent that we are required to use higher proportions of cash flow to finance capital expenditures or property acquisitions, the level of cash 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.

Changes in Legislation

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. Tax authorities having jurisdiction over us or the 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.

We intend to continue to qualify as a mutual fund trust for purposes of the Income Tax Act (Canada). 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 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 not constitute qualified investments for registered retirement savings plans (“RRSPs”), registered retirement income funds (“RRIFs”), registered education savings plans (“RESPs”) or deferred profit sharing plans. If, at the end of any month, one of these exempt plans holds Trust Units that are not qualified investments, the plan must pay a tax equal to one percent of the fair market value of the Trust Units at the time the Trust Units were acquired by the exempt plan. An RRSP or RRIF holding non-qualified Trust Units would be subject to taxation on income attributable to the Trust Units. If an RESP holds non-qualified Trust Units, it may have its registration revoked by the Canada Revenue Agency.

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 holders of Trust Units, particularly “non-residents” of Canada as defined in the Income Tax Act (Canada).

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

Environmental

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 and 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 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, management believes the political climate appears to favour new programs for environmental laws and regulation, particularly in relation to the reduction of emissions, and there is no assurance that any such programs, laws or regulations, if proposed and enacted, will not contain emission reduction targets which 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 Government of Canada’s Clean Air Act of 2006. The Clean Air Act proposes to reduce greenhouse gas emissions, however emission targets and compliance deadlines differ from those outlined in the Kyoto Protocol which was ratified by Canada. If passed, the Clean Air Act may have adverse operational and financial implications to the Trust. Provincial emission reduction requirements, such as those proposed in Alberta’s Bill 37 Climate Change and Emissions Management, 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. Although we believe that we are in material compliance with current applicable environmental regulations, 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 and 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”.

Kyoto Protocol

Canada is a signatory to the United Nations Framework Convention on Climate Change and has ratified the Kyoto Protocol established thereunder to set legally binding targets to reduce nationwide emissions of carbon dioxide, methane, nitrous oxide and other so-called “greenhouse natural gases”. Our exploration and production facilities and other operations and activities emit a small amount of greenhouse natural gases which may subject us to legislation regulating emissions of greenhouse natural gases. The Government of Canada has put forward a Climate Change Plan for Canada that suggests further legislation will set greenhouse natural gases emission reduction requirements for various industrial activities, including oil and natural gas exploration and production. While the protocol became legally binding on February 16, 2005, details of any specific requirements have not been released and as a result the potential impact on our operations and business is difficult to quantify. See “Industry Conditions — Environmental Regulation”.

Resource Plays — Enhanced Oil Recovery

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 and Cyclical Steam Stimulation), 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 delayed or cancelled EOR application in the Peace River Oil Sands project include but are not limited to the following: (i) changing economic conditions (commodity pricing, operating and capital expenditure fluctuations); (ii) changing engineering and technical conditions (ability to apply EOR methods to the reservoir and the production response thereto); (iii) 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; (iv) surface access and deliverability issues (First Nations relations, weather, pipeline, road and processing matters); and (v) financing (the availability of sufficient financing on acceptable terms).

The use or potential or planned use of CO2 miscible flooding to increase the oil recovery from large legacy oil pools such as Pembina, South Swan Hills and Midale 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: (i) CO2 infrastructure (the capture and transportation of the miscible agent to us at an economic cost); (ii) changing economic conditions (commodity pricing, operating and capital expenditure fluctuations); (iii) changing engineering and technical conditions (ability to apply CO2 EOR methods to the reservoir and the production response thereto); (iv) the large development program may need to be spread over a longer time period than planned due to capital allocation requirements; (v) surface access and deliverability issues (weather, pipeline, road and processing matters); and (vi) financing (the availability of sufficient financing on acceptable terms).

Coalbed Methane Projects (“CBM”)

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

Additional Financing

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. Management believes that the October 31 Proposals of the Government of Canada are expected to substantially eliminate the competitive advantage that we and other energy trusts enjoy relative to their industry competitors in raising capital in a tax-efficient manner. See “Risk Factors — Proposed Federal Tax Changes”. To the extent that we are required to use additional cash flow to finance capital expenditures or property acquisitions or to pay debt service charges or to reduce debt, the level of cash flow for distributions will be reduced.

Competition

There is strong competition relating to all aspects of the oil and gas industry. There are numerous trusts and conventional exploration and production companies in the oil and gas industry, who are also competing for the acquisitions of properties with longer life reserves and properties with exploitation and development opportunities. The October 31 Proposals of the Government of Canada are expected by management to make our Trust Units less attractive as consideration for acquisitions. See “Risk Factors — Proposed Federal Tax Changes”. As a result of such increasing competition, it is expected to become more difficult to acquire producing assets and reserves on beneficial terms. We also compete for skilled industry personnel with a substantial number of other oil and gas companies and trusts.

Non-Resident Ownership of Trust Units

In order for us to maintain our status as a mutual fund trust under the Income Tax Act (Canada), we must not be established or maintained primarily for the benefit of non-residents of Canada (“non-residents”) within the meaning of the Income Tax Act (Canada). The Trust Indenture provides that the Trust will use its best commercial efforts to maintain its status as a mutual fund trust under the Income Tax Act (Canada). See “Information Relating to the Trust — Trust Indenture — Limitations on Non-Resident Ownership”. Generally speaking, the Income Tax Act (Canada) provides that 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 of Canada (which is generally interpreted to mean that the majority of unitholders must not be non-residents of Canada), unless at all times after February 21, 1990, “all or substantially all” of the trust’s property consisted of property other than taxable Canadian property (the “TCP Exception”). Based on the most recent information obtained by Penn West through its transfer agent and financial intermediaries, in February 2007, we have estimated that in excess of 50% of the Trust’s issued and outstanding Trust Units were held by non-residents of Canada (as defined in the Income Tax Act (Canada)) at that time. The Trust has determined that it 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.

There is no assurance that the TCP Exception will continue to be available to the Trust or that the Government of Canada will not introduce new changes or proposals to tax regulations directed at non-resident ownership which, given the Trust’s level of non-resident ownership, may result in the Trust losing its mutual fund trust status or could otherwise detrimentally affect Penn West and the market price of the Trust Units. Penn West Petroleum Ltd. intends to continue to take the necessary measures in order to ensure the Trust continues to qualify as a mutual fund trust under the Income Tax Act (Canada), as it currently exists. See “Risk Factors — Changes in Legislation”.

Debt Service

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 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 is unsecured and we must comply with certain financial debt covenants. The lenders could, in the future, be provided with security over substantially all of our assets. In that event if we become unable to pay our debt service charges or otherwise commit an event of default such as bankruptcy, the lender may foreclose on or sell our oil and gas and other assets.

Asset Write-Downs

Canadian Generally Accepted Accounting Principles (“GAAP”) require that management apply certain accounting policies and make certain estimates and assumptions that affect reported amounts in our consolidated financial statements.

Under 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 cash 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 charge against earnings. The value of oil and gas properties is highly dependent upon the prices of oil and natural gas. Under United States GAAP, the estimated recoverable amounts are calculated based on estimated future net cash flows from proved reserves discounted at ten percent 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 United States GAAP than Canadian GAAP. See “Risk Factors — Volatility of Oil and Natural Gas Prices”.

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, 2006 we had $652 million recorded on our balance sheet as goodwill arising out of the Petrofund Merger. 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.

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. Such non-cash charges may be temporary in nature if the fair market value subsequently increases.

Regulatory

Oil and natural gas operations (exploration, production, pricing, marketing and transportation) are subject to extensive controls and regulations imposed by various levels of government that may be amended from time to time. See “Industry Conditions”. Our operations may 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.

Operational Matters

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, pollution, other environmental risks, fires and spills. Although we maintain insurance in accordance with customary industry practice, 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.

Continuing production from a property, and to some extent the marketing of production therefrom, are largely dependent upon the ability of the operator of the property. Operating costs on most properties have increased steadily over recent years. To the extent the operator fails to perform these functions properly, operating income may 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. Although satisfactory title reviews are generally conducted in accordance with industry standards, such reviews do not guarantee or certify that a defect in the chain of title may not arise to defeat our claim to certain of our oil and gas properties. A reduction of the income available for distributions could result in such circumstances.

Insurance

Our involvement in the exploration for and development of oil and natural gas properties could subject Penn West to liability for pollution, blowouts, property damage, personal injury or other hazards. Prior to commencing operations our operating entities 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, our operating entities 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 cash flow otherwise distributable by us.

Maintenance of Distributions

Future oil and natural gas reserves and hence revenues are highly dependent on our operating entities’ success in exploiting existing properties and acquiring additional reserves. We also distribute approximately 60 percent to 70 percent of our net cash flow to Unitholders rather than reinvesting it in reserve additions. Accordingly, if external sources of capital, including the issuance of additional Trust Units, become limited or unavailable on commercially reasonable terms, our operating entities’ ability to make the necessary capital investments to maintain or expand their oil and natural gas reserves will be impaired. To the extent that our operating entities are required to use cash flow to finance capital expenditures or property acquisitions, the level of cash 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 deplete 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 Trust Units and in a reduction in cash available for distributions to Unitholders.

Delay in Cash Distributions

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 our operating entities, 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.

Reliance on Management

Unitholders will be dependent on the management of Penn West Petroleum Ltd. in respect of the administration and management of all matters relating to our operations. Penn West Petroleum Ltd., as of December 31, 2006, operated approximately 70 percent of our total daily production. Investors who are not willing to rely on the management of Penn West Petroleum Ltd. should not invest in the Trust Units, or any future issuance of exchangeable shares and/or convertible debentures.

Expansion of Operations

The operations and expertise of management are currently focused on conventional oil and gas production and exploration and development in the Western Canadian Sedimentary Basin. In the future, we may acquire oil and gas properties outside this geographic area. 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, upgrades 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.

Net Asset Value

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

Return of Capital

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.

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 the Trust — Trust Indenture — Right of Redemption”. 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.

Nature of Trust Units

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 Penn West Petroleum Ltd. 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 will be the NPIs and other investments in securities of our operating entities including the 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 will be 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, the Trust is not registered under any trust and loan company legislation as it does not carry on or intend to carry on the business of a trust company.

Unitholder Limited Liability

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.

MATERIAL CONTRACTS

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

(a) the Trust Indenture;

(b) the Administration Agreement; and

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

TRANSFER AGENT AND REGISTRAR

The transfer agent and registrar for the Trust Units is CIBC Mellon Trust Company at its principal offices in Calgary, Alberta.

INTEREST OF MANAGEMENT AND OTHERS IN MATERIAL TRANSACTIONS

There were no material interests, direct or indirect, of directors and senior officers of Penn West Petroleum Ltd., any holder of Trust Units who beneficially owns more than 10 percent of the outstanding Trust Units, or any known associate or affiliate of such persons, in any transaction within the three most recently completed financial years which has materially affected or would materially affect us except for the matter disclosed in Note 17 under the heading “Related party transactions” of the consolidated financial statements for the years ending 2006 and 2005 which note is incorporated by reference in this Annual Information Form and which is filed on SEDAR at www.sedar.com.

INTERESTS OF EXPERTS

There is no person or company whose profession or business gives authority to a statement made by such person or company and who is named as having prepared or certified a statement, report or valuation 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, our independent engineering evaluator, and KPMG LLP, our auditors. As at the date hereof the designated professionals of GLJ Petroleum Consultants Ltd., as a group, beneficially owned, directly or indirectly, less than 1 per cent of our outstanding securities, including the securities of our associates and affiliates. KPMG LLP is the auditor of the Trust and is independent within the meaning of the Rules of Professional Conduct of the Institute of Chartered Accountants, Alberta.

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

ADDITIONAL INFORMATION

Additional information including remuneration of directors and officers of Penn West Petroleum Ltd., principal holders of the Trust Units and rights to purchase Trust Units, will be contained in the Information Circular which relates to the Annual Meeting of Unitholders to be held on June 8, 2007, and additional financial information is provided in our consolidated financial statements and management discussion and analysis of financial results for the year ended December 31, 2006 which have been filed on SEDAR at www.sedar.com.

APPENDIX C

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 MI 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 CEO, the CFO 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 CEO and CFO.

· 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) Multilateral 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 NI 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 NI 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 NI 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 VP Finance or their designates shall be available to attend at all meetings of the Committee upon the invitation of the Committee.

· The Controller, Treasurer and such other staff as appropriate to provide information to 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.

/s/ William E. Andrew		/s/ David Middleton
President and Chief Executive Officer		Executive Vice President and Chief Operating Officer

/s/ Murray Nunns		/s/ Thomas E. Philips
Director and Chairman of the Reserves Committee		Director and Member of the Reserves Committee

March 22, 2007

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

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

	(ii)	the related estimated future net revenue; and

(b)	(i)	proved oil and gas reserves estimated as at December 31, 2006 using constant prices and costs; and

	(ii)	the related estimated future net revenue.

	(a)	reviewed Penn West’s procedures for providing information to the independent qualified reserves evaluator;

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

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

	(a)	the content and filing with securities regulatory authorities of the reserves data and other oil and gas information;

	(b)	the filing of the report of the independent qualified reserves evaluator on the reserves data; and

	(c)	the content and filing of this report.

/s/ GLJ Petroleum Consultants Ltd.
Calgary, Alberta
February 28, 2007