ex99_1.htm

GENERAL DEVELOPMENT OF THE BUSINESS

History and Development

Year Ended December 31, 2006

NYSE Listing

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

Petrofund Acquisition

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

Other Acquisitions and Dispositions

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

Changes to Taxation of Income Trusts

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

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

The SIFT Tax provides that, while there is no intention to prevent "normal growth" during the transitional period, any "undue expansion" would result in the transition period being terminated with the loss of the benefit to us of that transitional period. As a result, the adverse tax consequences resulting from the SIFT Tax could be borne sooner than January 1, 2011. On December 15, 2006, the Department of Finance issued guidelines with respect to what is meant by "normal growth" in this context. Specifically, the Department of Finance stated that "normal growth" would include equity growth within certain "safe harbour" limits, measured by reference to a specified investment flow-through's (a "SIFT") market capitalization as of the end of trading on October 31, 2006 (which would include only the market value of the SIFT's issued and outstanding publicly-traded trust units, and not any convertible debt, options or other interests convertible into or exchangeable for trust units). Those safe harbour limits were 40 percent for the period from November 1, 2006 to December 31, 2007, and 20 percent each for each of the calendar years 2008, 2009 and 2010. Moreover, these limits were cumulative, so that any unused limit for a period carried over into the subsequent period. Additional details of the Department of Finance's guidelines include the following: (i) new equity for these purposes includes units and debt that is convertible into units (and may include other substitutes for equity if attempts are made to develop those); and (ii) replacing debt that was outstanding as of October 31, 2006 with new equity, whether by a conversion into trust units of convertible debentures or otherwise, will not be considered growth for these purposes and will therefore not affect the safe harbour.

On December 4, 2008, the Federal Minister of Finance announced changes to the guidelines discussed above to allow a SIFT to accelerate the utilization of the SIFT annual safe harbour amount for each of 2009 and 2010 so that the safe harbour amounts for 2009 and 2010 are available on and after December 4, 2008. This change does not alter the maximum permitted expansion threshold for a SIFT, but it allows a SIFT to use its normal growth room remaining as of December 4, 2008 in a single year, rather than staging a portion of the normal growth room over the 2009 and 2010 years. The Department of Finance has indicated that the issuance of trust units by a SIFT as consideration in connection with the acquisition of, or the merger with, another SIFT, will not be considered growth for these purposes and will therefore not affect a SIFT's safe harbour. Therefore, our issuance of Trust Units in connection with the acquisition of Canetic and Vault is not considered growth for these purposes and did not affect our safe harbour. The Department of Finance has also indicated that a SIFT's market capitalization for the purpose of calculating a SIFT's "safe harbour" equity growth limit is equal to the aggregate market capitalization of the SIFT and all SIFTs acquired by such SIFT as of the end of trading on October 31, 2006. The combined market capitalization of the Trust, Canetic and Vault as of the close of trading on October 31, 2006, having regard only to the issued and outstanding publicly-traded Trust Units and Canetic and Vault trust units at such date, was approximately $15 billion. We believe that, as at March 18, 2010, our remaining combined "safe harbour" equity growth amount for the period ending December 31, 2010 is approximately $14 billion (not including equity, including convertible debentures, issued to replace debt that was outstanding on October 31, 2006).

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

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

As a result of the enactment of the SIFT Tax in 2007, the future income taxes disclosed in our financial statements were adjusted to include temporary differences between the accounting and tax bases of our assets and liabilities at the trust level, as further described in Note 10 to our audited consolidated financial statements for the year ended December 31, 2009. In addition, the reported estimated net present value of future net revenues from our oil and natural gas reserves on an "after-tax" basis now reflects the impact of the SIFT Tax. We currently plan to convert to a dividend paying corporation prior to mid-2011. The timing of such conversion is dependent on a number of factors, including without limitation the strength of commodity prices and the equity markets, our operating performance, and the extent of our success in developing our inventory of prospects. We do not expect that a conversion to a corporation will have a major impact on our underlying operating strategy or business affairs, but cannot provide any assurances in this regard. We expect that such a conversion could be achieved without creating a taxable event for most of our Unitholders, particularly if a conversion were completed prior to January 1, 2013. However, going forward, the tax treatment of our distributions or dividends might be different for our Unitholders or shareholders, as the case may be, depending on the Unitholder's tax jurisdiction and whether the Unitholder holds its investment in a taxable account or tax-deferred account. For additional information on the SIFT Tax, including its potential impact on us and our Unitholders and the actions that we might take in response to the SIFT Tax (including with respect to our anticipated tax horizon), see the following: "Risk Factors" in this Annual Information Form; "Other Oil and Gas Information – Tax Horizon" in Appendix A-3 to this Annual Information Form; and "Update on SIFT Tax and Corporate Conversion" set forth in our management's discussion and analysis for the year ended December 31, 2009 (available on SEDAR at www.sedar.com and on EDGAR at www.sec.gov).

Year Ended December 31, 2007

April 2007 Asset Acquisition

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

Other Acquisitions and Dispositions

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

Private Placement of 2007 Senior Notes

Effective May 31, 2007, PWPL completed a private placement of an aggregate of US$475 million principal amount of notes (the "2007 Senior Notes"). The private placement consisted of the issuance of US$160 million principal amount of 5.68 percent notes due in 2015, US$155 million principal amount of 5.80 percent notes due in 2017, US$140 million principal amount of 5.90 percent notes due in 2019 and US$20 million principal amount of 6.05 percent notes due in 2022. The 2007 Senior Notes are unsecured and rank equally with Penn West's bank credit facilities, the 2008 Senior Notes, the 2008 Pounds Sterling Senior Notes, the 2009 Senior Notes and the 2010 Senior Notes. The proceeds of the 2007 Senior Notes were used to repay a portion of the indebtedness under Penn West's bank credit facilities.

Year Ended December 31, 2008

Vault Acquisition

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

In connection with the Vault Acquisition, Penn West also assumed approximately $89 million of bank indebtedness of Vault and approximately $99 million principal amount of convertible unsecured subordinated debentures of Vault (including the 7.2% Debentures, some of which continue to be outstanding at the date hereof).

Canetic Acquisition

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

In connection with the Canetic Acquisition, Penn West assumed approximately $1.4 billion of bank indebtedness of Canetic and approximately $261 million principal amount of convertible unsecured subordinated debentures of Canetic (including the 6.5% 2005 Debentures and the 6.5% 2006 Debentures, some of which continue to be outstanding at the date hereof).

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

Endev Acquisition

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

Other Acquisitions and Dispositions

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

Private Placement of 2008 Senior Notes

Effective May 29, 2008, PWPL completed a private placement of an aggregate of US$480 million and Cdn$30 million principal amount of senior guaranteed unsecured notes (the "2008 Senior Notes"). The private placement consisted of the issuance of US$153 million principal amount of 6.12 percent notes due in 2016, US$278 million principal amount of 6.30 percent notes due in 2018, Cdn$30 million principal amount of 6.16 percent notes due in 2018 and US$49 million principal amount of 6.40 percent notes due in 2020. The 2008 Senior Notes are unsecured and rank equally with PWPL's bank credit facilities and the 2007 Senior Notes, the 2008 Pounds Sterling Senior Notes, the 2009 Senior Notes and the 2010 Senior Notes. The proceeds of the private placement of the 2008 Senior Notes were used to repay a portion of the indebtedness outstanding under our bank credit facilities.

Private Placement of 2008 Pounds Sterling Senior Notes

Effective July 31, 2008, PWPL completed a private placement of an aggregate of £57 million principal amount of 7.78 percent senior guaranteed unsecured notes due in 2018 (the "2008 Pounds Sterling Senior Notes"). The 2008 Pounds Sterling Senior Notes are unsecured and rank equally with PWPL's bank credit facilities, the 2007 Senior Notes, the 2008 Senior Notes, the 2009 Senior Notes and the 2010 Senior Notes. The proceeds of the private placement of the 2008 Pounds Sterling Senior Notes were used to repay a portion of the indebtedness outstanding under our bank credit facilities.

Year Ended December 31, 2009

Public Offering of Trust Units

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

Reece Acquisition

Effective April 30, 2009, Penn West completed the Reece Acquisition, pursuant to which Penn West acquired Reece on the basis of an exchange of 0.125 of a Trust Unit for each one (1) common share of Reece. An aggregate of approximately 4.7 million Trust Units were issued. As a result of the Reece Acquisition, Penn West added production of approximately 1,900 boe per day and approximately 67,000 net acres of undeveloped land. Penn West also assumed approximately $42 million of debt and working capital in connection with the Reece Acquisition.

Private Placement of 2009 Senior Notes

Effective May 5, 2009, PWPL completed a private placement of an aggregate of US$154 million, £20 million, €10 million and Cdn$5 million principal amount of senior guaranteed unsecured notes (the "2009 Senior Notes"). The private placement consisted of the issuance of Cdn$5 million principal amount of 7.58 percent notes due in 2014, US$50 million principal amount of 8.29 percent notes due in 2014, US$35 million principal amount of 8.89 percent notes due in 2016, US$35 million principal amount of 8.89 percent notes due between 2013 and 2019, £20 million principal amount of 9.15 percent notes due in 2019, €10 million principal amount of 9.22 percent notes due in 2019 and US$34 million principal amount of 9.32 percent notes due in 2019. The 2009 Senior Notes are unsecured and rank equally with PWPL's bank credit facilities and the 2007 Senior Notes, the 2008 Senior Notes, the 2008 Pounds Sterling Senior Notes and the 2010 Senior Notes. The proceeds of the private placement of the 2009 Senior Notes were used to repay a portion of the indebtedness outstanding under our bank credit facilities.

Cancellation of Credit Facility Tranche B

On November 6, 2009, Penn West cancelled the $750 million Tranche B of its $4 billion credit facility. The remaining $3.25 billion matures January 11, 2011. Penn West is currently in the process of renewing its credit facility with its bank syndicate and believes it will be successful in renewing the facility on acceptable terms prior to the date of expiry.

November 2009 Asset Disposition

On November 30, 2009, Penn West completed the disposition (the "November 2009 Asset Disposition") of certain heavy oil assets located primarily in the Lloydminster area of Alberta and Saskatchewan. Pursuant to the transaction, Penn West disposed of approximately 6,000 boe per day of current production and approximately 10,000 net acres of undeveloped land. The proceeds of the November 2009 Asset Disposition were used to repay a portion of the indebtedness outstanding under our bank credit facilities.

Other Acquisitions and Dispositions

Including the November 2009 Asset Disposition, we completed property dispositions, net of acquisitions, of $369 million in 2009.

2010 Developments

Asset Exchange Agreement

On January 15, 2010, Penn West closed an asset exchange transaction (the "Asset Exchange Transaction") pursuant to which we increased our position in our light-oil resource plays in the Pembina and Dodsland areas. Pursuant to the transaction, Penn West acquired production of approximately 560 boe per day, In exchange for these properties, Penn West disposed of certain interests in the Leitchville area with approximately 3,500 boe per day of production and received net cash proceeds of approximately $434 million, which amount was used to repay a portion of the indebtedness outstanding under our bank credit facilities.

Private Placement of 2010 Senior Notes

Effective March 16, 2010, PWPL completed a private placement of an aggregate of US$250 million and Cdn $50 million senior guaranteed unsecured notes (the "2010 Senior Notes"). The private placement consisted of the issuance of US$27.5 million principal amount of 4.53 percent notes due in 2015, US$65 million principal amount of 5.29 percent notes due in 2017, US$112.5 million principal amount of 5.85 percent notes due in 2020, US$25 million principal amount of 5.95 percent notes due in 2022, US$20 million principal amount of 6.10 percent notes due in 2025, and Cdn$50 million principal amount of 4.88 percent notes due in 2015. The 2010 Senior Notes are unsecured and rank equally with PWPL's bank credit facilities and the 2007 Senior Notes, the 2008 Senior Notes, the 2008 Pounds Sterling Senior Notes and the 2009 Senior Notes. The proceeds of the private placement of the 2010 Senior Notes were used to repay a portion of the indebtedness outstanding under our bank credit facilities.

Alberta Competitiveness Review

On March 11, 2010, the Government of Alberta, announced changes to its royalty structure which will become effective January 1, 2011. These modifications include a reduction in the maximum royalty rate from current levels of 50 percent to 40 percent for conventional oil and from 50 percent to 36 percent for natural gas. Furthermore, the current incentive allowing a maximum 5 percent royalty rate on the first year of production from new conventional oil and natural gas wells will remain in effect under the modified framework. Additionally, the royalty curves will be reviewed which may lead to modifications for all production types. Changes to the royalty curves, if any, will be announced prior to May 31, 2010, therefore, Penn West cannot estimate the full impact of the modifications until that time.

Other Acquisitions and Dispositions

In addition to the Asset Exchange Transaction described above, as of the date hereof we have completed property dispositions, net of acquisitions, of approximately $13 million in 2010. Including the Asset Exchange Transaction, as of the date hereof we have completed property dispositions, net of acquisitions, of approximately $447 million in 2010.

Ongoing Acquisition and Disposition Activities

Potential Acquisitions

Penn West continues to evaluate potential acquisitions of all types of petroleum and natural gas and other energy-related assets as part of its on-going asset portfolio management program. Penn West is normally in the process of evaluating several potential acquisitions at any one time which individually or together could be material. As of the date hereof, Penn West has not reached agreement on the price or terms of any potential material acquisitions. Penn West cannot predict whether any current or future opportunities will result in one or more acquisitions for Penn West.

Potential Dispositions and Farm-Outs

Penn West continues to evaluate potential dispositions of its petroleum and natural gas assets as part of its on-going portfolio asset management program. In addition, Penn West continues to evaluate potential farm-out opportunities with other industry participants in respect of its petroleum and natural gas assets in circumstances where Penn West believes it is prudent to do so based on, among other things, its capital program, development plan timelines and the risk profile of such assets. Penn West is normally in the process of evaluating several potential dispositions of its assets and farm-out opportunities at any one time, which individually or together could be material. As of the date hereof, Penn West has not reached agreement on the price or terms of any potential material dispositions or farm-outs. Penn West cannot predict whether any current or future opportunities will result in one or more dispositions or farm-outs for Penn West.

Significant Acquisitions

Penn West has not completed an acquisition during its most recently completed financial year and up to the date of this document that is a significant acquisition for the purposes of Part 8 of National Instrument 51-102. In addition, there are no proposed acquisitions that have progressed to a state where a reasonable person would believe that the likelihood of the acquisition being completed is high and that would be a significant acquisition for the purposes of Part 8 of National Instrument 51-102 if completed as of the date of this Annual Information Form.

DESCRIPTION OF OUR BUSINESS

Overview

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

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

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

As at March 18, 2010, we had approximately 1,950 employees.

PWPL

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

Internal Notes

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

NPIs

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

Reserves Data

See Appendices A-1, A-2 and A-3 for complete NI 51-101 oil and gas reserves disclosure for Penn West as at December 31, 2009.

CAPITALIZATION OF PWPL

Common Shares

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

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

Preferred Shares

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

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

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

Borrowing

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

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

INFORMATION RELATING TO PENN WEST

Trust Units

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

As at March 18, 2010, approximately 424,041,667 Trust Units were outstanding, approximately 4,739,450 Trust Units were reserved for issuance on conversion of the Convertible Debentures and approximately 39,598,226 Trust Units were reserved for issuance pursuant to incentive rights that have been issued pursuant to Penn West's trust unit rights incentive plan.

Special Voting Units

The Trust Indenture also provides for the issuance of special voting units which are entitled to such number of votes at meetings of Unitholders and any other rights or limitations prescribed by the Board of Directors when the Board of Directors authorizes issuing such special voting units. The Trust Units and the special voting units vote together as a single class on all matters. In the event of Penn West's liquidation, dissolution or winding-up, the holders of special voting units will not be entitled to receive any of Penn West's assets available for distribution to Unitholders. The holders of special voting units will not be entitled to receive dividends or other distributions from Penn West. As at the date hereof, no special voting units are issued and outstanding.

Convertible Debentures

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

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

The 7.2% Debentures were originally issued in the aggregate principal amount of $50 million and approximately $26 million principal amount was outstanding at March 18, 2010. The 7.2% Debentures mature on May 31, 2011.

The 6.5% 2006 Debentures were originally issued in the aggregate principal amount of $230 million and $229 million principal amount was outstanding at March 18, 2010. The 6.5% 2006 Debentures mature on December 31, 2011.

Terms of Convertible Debentures

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

The principal amount of the Convertible Debentures is payable in lawful money of Canada or, at the option of the Trust and subject to applicable regulatory approval, by payment of Trust Units as further described under "Payment Upon Redemption or Maturity" and "Redemption and Purchase". The interest on the Convertible Debentures is payable in lawful money of Canada and, in the case of the 6.5% 2005 Debentures and the 6.5% 2006 Debentures, at the option of the Trust and subject to applicable regulatory approval, by the delivery to the Debenture Trustee of Trust Units in accordance with the Unit Interest Payment Election described under "Interest Payment Option".

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

Conversion Privilege

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

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

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

Redemption and Purchase

The Trust may, on not more than 60 days and not less than 30 days prior notice, redeem the 6.5% 2005 Debentures at a redemption price of $1,025 per 6.5% 2005 Debenture at any time prior to their maturity, plus accrued and unpaid interest thereon, if any.

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

The Trust may, on not more than 60 days and not less than 30 days prior notice, redeem the 7.2% Debentures at a redemption price of $1,050 per 7.2% Debenture on or before May 31, 2010, and at a price of $1,025 per 7.2% Debenture after May 31, 2010 and before maturity, in each case plus accrued and unpaid interest thereon, if any.

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

Payment upon Redemption or Maturity

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

Subordination

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

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

The Convertible Debentures are effectively subordinate to claims of creditors of the Trust's Subsidiaries except to the extent the Trust is a creditor of such Subsidiaries ranking at least pari passu with such other creditors. Specifically, the Convertible Debentures are subordinated in right of payment to the prior payment in full of all indebtedness under the Trust's credit facilities and to the prior payment in full of the 2007 Senior Notes, the 2008 Senior Notes, the 2008 Pounds Sterling Senior Notes, the 2009 Senior Notes and the 2010 Senior Notes.

Priority over Trust Distributions

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

Change of Control of the Trust

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

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

Interest Payment Option

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

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

Events of Default

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

Offers for Debentures

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

Modification

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

Limitation on Issuance of Additional Convertible Debentures

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

Limitation on Non-Resident Ownership

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

Book-Entry System for Convertible Debentures

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

Ratings

Penn West has neither asked for nor received a stability rating, and it is not aware that it has received any other kind of rating, including a provisional rating, from one or more approved rating organizations for outstanding securities of Penn West, which rating or ratings continue in effect.

Trust Indenture

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

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

Trustee

CIBC Mellon Trust Company was appointed our trustee on May 27, 2005 and also acts as the transfer agent for the Trust Units. The Trustee is responsible for, among other things, accepting subscriptions for Trust Units and issuing Trust Units pursuant thereto, maintaining our books and records and providing timely reports to holders of Trust Units. The Trust Indenture provides that the Trustee shall exercise its powers and carry out its functions thereunder as Trustee honestly, in good faith and in the Trust's best interests and in the best interest of the Unitholders and, in connection therewith, shall exercise that degree of care, diligence and skill that a reasonably prudent trustee would exercise in comparable circumstances.

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

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

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

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

Future Offerings

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

Meetings and Voting

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

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

Our Management

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

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

Limitation on Non-Resident Ownership

In order for the Trust to maintain its status as a mutual fund trust under the Tax Act, it must not be established or maintained primarily for the benefit of Non-Residents unless it satisfies the requirements of certain exceptions. The Trust Indenture provides that Penn West will use its best commercial efforts to maintain its status as a mutual fund trust under the Tax Act. Generally speaking, the Tax Act provides that a trust will permanently lose its "mutual fund trust" status (which is essential to the income trust structure) if it is established or maintained primarily for the benefit of Non-Residents (which is generally interpreted to mean that the majority of unitholders must not be Non-Residents), unless at the relevant time "all or substantially all" of the trust's property consists of property other than taxable Canadian property (the "TCP Exception"). We have determined that Penn West currently meets the requirement of the TCP Exception, and as a result, the Trust Indenture does not currently have a specific limit on the percentage of Trust Units that may be owned by Non-Residents.

Right of Redemption

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

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

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

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

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

Since the inception of the Trust, there have been no redemptions of Trust Units.

Termination of the Trust

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

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

Reporting to Unitholders

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

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

CORPORATE GOVERNANCE

General

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

Trust Indenture

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

Decision Making

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

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

Distributions and Distribution Policy

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

The Board of Directors (on behalf of the Trust) reviews the distribution policy from time to time. Distributions are not guaranteed and the amount that we distribute per Trust Unit on a monthly basis may be reduced from time to time, or even eliminated. The actual amount distributed will be dependent on various factors, including, but not limited to, the commodity price environment, the amount of capital expenditures that we make, our production levels and numerous other economic and operational factors, many of which are beyond our control. The amount of distributions that we make (if any) is at the discretion of the Board of Directors of PWPL. See "Risk Factors". The current distribution policy targets the use of approximately 40 percent to 50 percent of funds flow for distribution to Unitholders. Depending upon various factors, including commodity prices and the size of Penn West's capital budget, it is expected that approximately 50 percent to 60 percent of funds flow will fund all or a portion of Penn West's annual capital expenditure program, including exploration and exploitation expenditures and minor property acquisitions, but excluding major acquisitions.

Distributions are normally announced on a quarterly 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 Penn West in a fiscal year not previously distributed in that fiscal year must be distributed to Unitholders of record on December 31 of such year. This excess income, if any, will be allocated to Unitholders of record at December 31 but the right to receive this income, if the amount is not determined and declared payable at December 31, will trade with the Trust Units until determined and declared payable in accordance with the rules of the TSX. To the extent that a Unitholder trades Trust Units in this period they will be allocated such income but will dispose of their right to receive the cash or Trust Units comprising such a distribution.

The credit agreement governing PWPL's syndicated credit facility and each of the note purchase agreements governing the 2007 Senior Notes, the 2008 Senior Notes, the 2008 Pounds Sterling Senior Notes, the 2009 Senior Notes and the 2010 Senior Notes, contain provisions which restrict the ability of the Trust to pay distributions to Unitholders in the event of the occurrence of certain events of default. For further information regarding the credit agreement governing our syndicated credit facility, reference is made to Note 6 (Long-Term Debt) of our consolidated financial statements for the year ended December 31, 2009. For further information regarding the note purchase agreements governing the 2007 Senior Notes, the 2008 Senior Notes, the 2008 Pounds Sterling Senior Notes and the 2009 Senior Notes, reference is made to Note 6 (Long-term debt) of our consolidated financial statements for the year ended December 31, 2009, which note is incorporated by reference in this Annual Information Form. Our consolidated financial statements for the year ended December 31, 2009 are filed on SEDAR at www.sedar.com.

Directors and Executive Officers of PWPL

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

Name, Province/State and Country of Residence	Positions and Offices Held	Principal Occupations during the Five Preceding Years

James E. Allard(1)(5)(6) Alberta, Canada	Director since June 30, 2006	Independent director and business advisor. Also, a member of the Alberta Securities Commission from 1999 to 2005.

William E. Andrew Alberta, Canada	Chief Executive Officer Director since June 3, 1994	Chief Executive Officer of PWPL since January 11, 2008. Prior thereto, President and Chief Executive Officer of PWPL since May 2005. Prior thereto, President of PWPL.

Robert G. Brawn(3)(5) Alberta, Canada	Director since January 11, 2008	President of 738831 Alberta Ltd. (a private investment company) since 2003. Prior thereto, Chairman of Acclaim Energy Inc. ("Acclaim"), the administrator of Acclaim Energy Trust (a public oil and gas income trust), a predecessor of Canetic.

George H. Brookman(2)(4) Alberta, Canada	Director since August 3, 2005	President and Chief Executive Officer of West Canadian Industries Group Inc. (a commercial digital printing and graphics company).

Name, Province/State and Country of Residence	Positions and Offices Held	Principal Occupations during the Five Preceding Years

John A. Brussa Alberta, Canada	Chairman of the Board of Directors Director since April 21, 1995	Senior Partner, Burnet, Duckworth & Palmer LLP (barristers and solicitors).

Daryl Gilbert(2)(3) Alberta, Canada	Director since January 11, 2008	Independent businessman since 2005 and Managing Director of JOG Capital Inc., a private equity investment management company, since 2008. In addition, corporate director of a number of oil and natural gas related companies.

Shirley A. McClellan(1)(4)(5) Alberta, Canada	Director since June 8, 2007	Distinguished Scholar in Residence at the University of Alberta for the Faculties of Agriculture and Rural Economy and the School of Business. Independent businesswoman since 2007. Prior thereto, Deputy Premier of the Province of Alberta from 2001 to 2007 and Minister of Finance of the Province of Alberta from 2004 to 2007.

Murray R. Nunns Alberta, Canada	President and Chief Operating Officer Director since June 9, 2009	President and Chief Operating Officer of PWPL since February 8, 2008. Prior thereto, director of PWPL and Executive Chairman of Monterey Exploration Ltd., a public oil and gas company. Prior thereto, a variety of management positions at Rio Alto Exploration Ltd., a public oil and gas company.

Frank Potter(1)(4)(6) Ontario, Canada	Director since June 30, 2006	Chairman of Emerging Markets Advisors, Inc. (an investment consulting firm).

R. Gregory Rich(2)(4) Texas, United States	Director since January 11, 2008	Principal of Blackrock Energy Associates (an energy consulting and investment firm) since October 2002.

Jack Schanck(3)(5) Texas, United States	Director since June 2, 2008	Independent businessman since January 1, 2010. Managing Partner of Tecton Energy, LLC (a Texas-based oil and natural gas exploration and production company) from 2007 to 2009. Prior thereto, Chief Executive Officer of SouthView Energy LLC (an oil and natural gas investment company) from 2005 to 2007. Prior thereto, Co-Chief Executive Officer of Samson Investment Company.

James C. Smith(1)(2)(3) Alberta, Canada	Director since May 31, 2005	Independent director and consultant to a number of public and private oil and gas companies.

Mark P. Fitzgerald Alberta, Canada	Senior Vice President, Production	Senior Vice President, Production of PWPL since November 3, 2008. Prior thereto, Senior Vice President, Engineering of PWPL since January 11, 2008. Prior thereto, Vice President, Operations of Canetic since January 2006. Prior thereto, Vice President, Operations of Acclaim since February 2005.

Name, Province/State and Country of Residence	Positions and Offices Held	Principal Occupations during the Five Preceding Years


Hilary Foulkes Alberta, Canada	Senior Vice President, Business Development	Senior Vice-President, Business Development of PWPL since April 29, 2008. Prior thereto, a Managing Director with the investment banking firm, Scotia Waterous for eight years.

Thane A.E. Jensen Alberta, Canada	Senior Vice President, Operations Engineering	Senior Vice President, Operations Engineering of PWPL since November 3, 2008. Prior thereto, Senior Vice President, Exploration and Development of PWPL since 2005.

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

David W. Middleton Alberta, Canada	Executive Vice President, Engineering and Corporate Development	Executive Vice President, Engineering and Corporate Development of PWPL since November 3, 2008. Prior thereto, Executive Vice President, Operations and Corporate Development of PWPL since February 8, 2008. Prior thereto, Chief Operating Officer of PWPL since January 11, 2008. Prior thereto, Executive Vice President and Chief Operating Officer of PWPL since 2005.

Bob Shepherd Alberta, Canada	Senior Vice President, Exploration and Development	Senior Vice President, Exploration and Development of PWPL since October 1, 2009. Prior thereto, Vice President Exploitation of PWPL, since January 22, 2009. Prior thereto, President of Laser Energy Inc since 2007. Prior thereto, General Manager, Oil Sands of Husky Oil Operations Ltd since 2004.

Todd H. Takeyasu Alberta, Canada	Executive Vice President and Chief Financial Officer	Executive Vice President and Chief Financial Officer of PWPL since February 8, 2008. Prior thereto, Senior Vice President, Finance – Treasury of PWPL since January 11, 2008. Prior thereto, Senior Vice President and Chief Financial Officer of PWPL since 2006. Prior thereto, Vice President, Finance of PWPL since 2005.

Notes:

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

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

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

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

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

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

As at March 18, 2010, the directors and executive officers of PWPL, as a group, beneficially owned, or controlled or directed, directly or indirectly, approximately one million Trust Units or less than one percent of the issued and outstanding Trust Units.

Cease Trade Orders, Bankruptcies, Penalties or Sanctions

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

(a)

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

(b)

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

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

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

(a)

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

(b)

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

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 in 2002. The reorganization resulted in the creation of two public corporations, Imperial Metals Corporation and IEI Energy Inc. (subsequently renamed Rider Resources Ltd.), both of which were listed on the TSX.

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

(a)

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

(b)

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

Conflicts of Interest

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

It is acknowledged in the Codes that the directors may be directors or officers of other entities engaged in the oil and gas business, and that such entities may compete directly or indirectly with Penn West. Passive investments in public or private entities of less than one per cent of the outstanding shares will not be viewed as "competing" with Penn West. No executive officer or employee of PWPL should be a director or officer of any entity engaged in the oil and gas business unless expressly authorized by the Board of Directors. Any director of PWPL who is actively engaged in the management of, or who owns an investment of one per cent or more of the outstanding shares, in public or private entities shall disclose such holding to the Board of Directors. In the event that any circumstance should arise as a result of such positions or investments being held or otherwise which in the opinion of the Board of Directors constitutes a conflict of interest which reasonably affects such person's ability to act with a view to the best interests of Penn West, the Board of Directors will take such actions as are reasonably required to resolve such matters with a view to the best interests of Penn West. Such actions, without limitation, may include excluding such directors, officers or employees from certain information or activities of Penn West.

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

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

Promoters

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

AUDIT COMMITTEE DISCLOSURES

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

Composition of the Audit Committee and Relevant Education and Experience

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

James C. Smith (Chairman)

Mr. Smith is a Chartered Accountant with over 38 years of experience in public accounting and industry. Since 1998, he has been a business consultant and independent director to a number of public and private companies operating in the oil and natural gas industry. From February 2002 to June 2006, he served as the Vice-President and Chief Financial Officer of Mercury Energy Corporation, a private oil and natural gas company. Mr. Smith also held the position of Chief Financial Officer of Segue Energy Corporation, a private oil and natural gas company, from January 2001 to August 2003. From 1999 to 2000, Mr. Smith was the Vice-President and Chief Financial Officer of Probe Exploration Inc., a publicly traded oil and natural gas company. Mr. Smith served as the Vice-President and Chief Financial Officer of Crestar Energy Inc. from its inception in 1992 until 1998, during which time the company completed an initial public offering, was listed on the TSX and completed several major debt and equity financing transactions.

James E. Allard

Mr. Allard is an independent director and business advisor. He has a Bachelor of Science degree in Business Administration from the University of Connecticut and completed the Advanced Management Program at Harvard University. Mr. Allard has focused his career on international finance in the petroleum industry for the past 41 years, during which time he has served as the Chief Executive Officer, Chief Financial Officer and/or a director of a number of publicly traded and private companies. Over the past nine years he has served on the board of the Alberta Securities Commission, acted as the sole external trustee and advisor to a mid-sized pension plan and served as a director and advisor to several companies. From 1981 to 1995, Mr. Allard served as a senior executive officer of Amoco Corporation and as a director of Amoco Canada, which at that time was Canada's largest natural gas producer.

Frank Potter

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

Shirley A. McClellan

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

Pre-Approval Policies and Procedures for Non-Audit Services

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

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

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

External Auditor Service Fees

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

Year	Audit Fees(1) ($)		Audit Related Fees(2) ($)		Tax Fees(3) ($)		All Other Fees(4) ($)
2009		1,220,000		530,000		9,155		-
2008		1,550,000		562,500		3,712		-

Notes:

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

(2)

The aggregate fees billed in each of the last two fiscal years by our external auditor for assurance and related services that are reasonably related to the performance of the audit or review of our financial statements (and not included in audit services fees in note (1)). The services comprising the fees disclosed under this category principally consisted of French translation services, long-form comfort letters related to the public offering of Trust Units, consultations related to International Financial Reporting Standards and matters related to the corporate acquisitions completed in 2009 and 2008.

(3)

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

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

Reliance on Exemptions

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

Audit Committee Oversight

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

DISTRIBUTIONS TO UNITHOLDERS

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

Month	2010 ($)		2009 ($)		2008 ($)		2007 ($)
January		0.15		0.23		0.34		0.34
February		0.15		0.23		0.34		0.34
March		0.15		0.23		0.34		0.34
April		-		0.15		0.34		0.34
May		-		0.15		0.34		0.34
June		-		0.15		0.34		0.34
July		-		0.15		0.34		0.34
August		-		0.15		0.34		0.34
September		-		0.15		0.34		0.34
October		-		0.15		0.34		0.34
November		-		0.15		0.34		0.34
December		-		0.15		0.34		0.34
Total		0.45		2.04		4.08		4.08

Future distributions are subject to the discretion of the Board of Directors and may vary depending on, among other things, the current and anticipated commodity price environment, our production levels and the amount of capital expenditures that we make. Cash distributions to Unitholders are not assured or guaranteed. See "Corporate Governance – Distributions and Distribution Policy" and "Risk Factors".

MARKET FOR SECURITIES

Trust Units

The Units are listed and traded on the TSX under the symbol PWT.UN and on the NYSE under the symbol PWE. The following tables set forth certain trading information for our Trust Units in 2009 as reported by the TSX and the NYSE.

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

January		16.18		13.55		28,122,634
February		14.08		10.94		28,127,890
March		14.19		8.82		43,761,160
April		13.85		11.51		31,291,751
May		15.48		13.08		27,209,018
June		15.92		13.67		23,775,522
July		14.89		12.51		18,345,957
August		14.87		13.75		16,938,434
September		16.98		13.60		27,357,009
October		19.15		15.30		28,132,716
November		19.49		17.50		20,623,334
December		18.95		17.36		12,868,963

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

January		13.72		11.06		74,868,480
February		11.57		8.66		72,387,176
March		11.54		6.77		97,564,920
April		11.45		9.07		58,198,880
May		14.19		10.99		67,340,968
June		14.68		11.83		58,821,888
July		13.78		10.70		47,887,368
August		13.68		12.40		38,951,248
September		15.84		12.28		58,719,664
October		18.24		14.07		78,045,184
November		18.48		16.27		52,157,108
December		18.18		16.43		39,525,544

Convertible Debentures Assumed Pursuant to the Vault Acquisition

We assumed the 7.2% Debentures from Vault on January 10, 2008 in connection with the Vault Acquisition. On January 15, 2008, the 7.2% Debentures began trading on the TSX as our securities under the symbol "PWT.DB.E".

The following table sets forth certain trading information for our 7.2% Debentures in 2009 as reported by the TSX (with each unit of volume traded being equal to $100 principal amount of 7.2% Debentures).

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

January		98.00		90.00		1,550
February		99.45		91.51		1,070
March		95.00		88.00		24,470
April		99.46		91.51		16,420
May		100.00		96.50		23,870
June		101.00		95.00		10,610
July		100.50		98.50		6,600
August		102.00		100.00		14,000
September		102.50		100.30		10,960
October		101.50		100.10		22,880
November		103.00		101.30		5,360
December		104.30		102.00		3,050

Convertible Debentures Assumed Pursuant to the Canetic Acquisition

We assumed the 6.5% 2005 Debentures and the 6.5% 2006 Debentures from Canetic on January 11, 2008 in connection with the completion of the Canetic Acquisition. On January 16, 2008, the 6.5% 2005 Debentures and the 6.5% 2006 Debentures began trading on the TSX as our securities under the symbols "PWT.DB.D" and "PWT.DB.F", respectively.

6.5% 2005 Debentures

The following table sets forth certain trading information for our 6.5% 2005 Debentures in 2009 as reported by the TSX (with each unit of volume traded being equal to $100 principal amount of 6.5% 2005 Debentures).

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

January		100.00		85.00		3,700
February		100.00		93.00		4,850
March		100.00		91.00		2,660
April		100.00		97.00		2,340
May		100.00		97.50		7,800
June		103.00		99.65		2,690
July		101.00		100.00		1,780
August		101.50		100.75		1,020
September		102.00		100.75		2,890
October		102.45		100.76		3,760
November		102.25		101.53		2,910
December		102.99		100.77		1,910

6.5% 2006 Debentures

The following table sets forth certain trading information for our 6.5% 2006 Debentures in 2009 as reported by the TSX (with each unit of volume traded being equal to $100 principal amount of 6.5% 2006 Debentures).

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

January		94.00		82.00		131,940
February		93.00		87.00		220,230
March		93.00		84.50		92,770
April		96.00		91.50		16,420
May		98.25		95.50		47,090
June		99.85		97.75		57,130
July		100.60		97.00		41,720
August		101.50		99.75		35,760
September		102.00		100.50		25,860
October		102.90		100.25		24,250
November		103.00		102.00		16,090
December		103.00		100.75		17,585

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

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, marketing and pollution) 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, Saskatchewan and Manitoba, 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 a licence requires a public hearing and the approval of the Governor in Council.

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

The governments of Alberta, British Columbia and Saskatchewan also regulate the volume of natural gas that may be removed from those provinces for consumption elsewhere based on such factors as reserve availability, transportation arrangements, and market considerations. At present, Manitoba does not have natural gas production in commercial quantities and therefore does not impose such export restrictions.

Pipeline Capacity

Although pipeline expansions are ongoing, transport restrictions can occur from time to time which could potentially impede the access of our products to market. In addition, the pro-rationing of capacity on the inter-provincial pipeline systems could from time to time also potentially affect our 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, the 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, that any prohibition in any circumstances in which any other form of quantitative restriction is applied is prohibited, and in the case of import-price requirements, that 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, all of which are important for Canadian oil and natural gas exports.

Provincial Royalties and Incentives

General

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

Occasionally the governments of the western Canadian provinces create incentive programs for exploration and development. Such programs often provide for royalty rate reductions, royalty holidays, or royalty 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.

The Canadian federal corporate income tax rate levied on taxable income is 18 percent effective January 1, 2010 for active business income including resource income and will decrease to 15 percent in two additional steps: 16.5 percent on January 1, 2011; and 15 percent on January 1, 2012.

Alberta

In Alberta, companies are granted the right to explore, produce and develop petroleum and natural gas resources underlying Crown lands in exchange for royalties, bonus bid payments at land sales and annual land rents. On October 25, 2007, the Government of Alberta released a report entitled "The New Royalty Framework" (the "NRF") containing the Government's proposals for Alberta's new royalty regime, which proposals were implemented by the Mines and Minerals (New Royalty Framework) Amendment Act, 2008, which was given Royal Assent on December 2, 2008. The NRF and the applicable new legislation became effective on January 1, 2009. On March 11, 2010, the Government of Alberta announced changes to Alberta's royalty regime that are intended to increase Alberta's competitiveness in the upstream oil and natural gas sectors; specifically, the maximum royalty rates for conventional oil and natural gas production will be decreased effective for the January 2011 production month and certain temporary incentive programs currently in place will be made permanent. Further details with respect to the changes to Alberta's royalty system, including the finalization of royalty curves, are expected to be provided in the coming months.

With respect to conventional oil, the NRF eliminated the classification system used by the previous royalty structure which classified oil based on the date of discovery of the pool. Under the NRF, royalty rates for conventional oil are set by a single sliding rate formula which is applied monthly and incorporates separate variables to account for production rates and market prices. Royalty rates for conventional oil under the NRF range from 0 to 50 percent, an increase from the previous maximum royalty rates of 30 to 35 percent depending on the vintage of the oil, and rate caps are set at $120 per barrel. Effective January 1, 2011, the maximum royalty payable under the NRF will be reduced to 40 percent.

Royalty rates for natural gas under the NRF are similarly determined using a single sliding rate formula incorporating separate variables to account for production rates and market prices. Royalty rates for natural gas under the NRF range from 5 to 50 percent, an increase from the previous maximum royalty rates of 5 to 35 percent, and rate caps are set at $17.75/GJ. Effective January 1, 2011, the maximum royalty payable under the NRF will be reduced to 36 percent.

Oil sands projects are also subject to the NRF. Prior to payout, the royalty is payable on gross revenues of an oil sands project. Gross revenue royalty rates range between 1 and 9 percent depending on the market price of oil: rates are 1 percent when the market price of oil is less than or equal to $55 per barrel and increase for every dollar of market price of oil increase to a maximum of 9 percent when oil is priced at $120 or higher. After payout, the royalty payable is the greater of the gross revenue royalty based on the gross revenue royalty rate of 1 to 9 percent and the net revenue royalty based on the net revenue royalty rate. Net revenue royalty rates start at 25 percent and increase for every dollar of market price of oil increase above $55 up to 40 percent when oil is priced at $120 or higher. An oil sands project reaches payout when its cumulative revenue exceeds its cumulative costs. Costs include specified allowed capital and operating costs related to the project plus a specified return allowance. As part of the implementation of the NRF, the Government of Alberta renegotiated existing contracts with certain oil sands producers that were not compatible with the NRF.

In August 2006, the Government of Alberta introduced the Innovative Energy Technologies Program (the "IETP"), which has a stated objective of promoting producers' investment in research, technology and innovation for the purposes of improving environmental performance while creating commercial value. The IETP is backed by a $200 million funding commitment over a five-year period beginning April 1, 2005 and provides royalty adjustments to specific pilot and demonstration projects that utilize innovative technologies to increase recovery from existing reserves.

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

In response to the drop in commodity prices experienced during the second half of 2008, the Government of Alberta announced on November 19, 2008, the introduction of a five-year program of transitional royalty rates with the intent of promoting new drilling. Companies drilling new natural gas or conventional deep oil wells (between 1,000 and 3,500 metres) were given a one time option to adopt, on a well-by-well basis, the transitional royalty rates or those outlined in the NRF. Pursuant to the changes made to Alberta's royalty structure announced on March 11, 2010, producers will only be able to elect to adopt the transitional royalty rates prior to January 1, 2011 and producers that have already elected to adopt the transitional royalty rates as of that date will be permitted to switch to Alberta's conventional royalty structure. On December 31, 2013, all producers operating under the transitional royalty rates will automatically become subject to Alberta's conventional royalty structure.

On March 3, 2009, the Government of Alberta announced a three-point incentive program to stimulate new and continued economic activity in Alberta. The program applies to wells drilled between April 1, 2009 and March 31, 2011 and includes a drilling royalty credit for new conventional oil and natural gas wells and a new well royalty incentive program with a 5 percent royalty rate for the first 12 months of production on a maximum of 50,000 bbls of oil or 500 MMcf of gas, whichever is achieved first. On March 11, 2010, the Government of Alberta announced that the incentive program royalty rate of 5 percent for the first 12 months of production would be made permanent, with the same volume limitations. The three-point incentive program also includes an investment of $30 million by the Government of Alberta in abandonment and reclamation projects for orphan wells. The stated objective of this investment is to encourage the cleanup of inactive oil and gas wells and to stimulate new activity within the services sector.

In addition to the foregoing, Alberta currently maintains a royalty reduction program for low productivity oil and oil sands wells, a royalty adjustment program for deep marginal gas wells, and a royalty exemption for re-entry wells, among others.

The NRF includes a policy of "shallow rights reversion". The Government of Alberta started to implement this policy on January 1, 2009, and its intent is to maximize the development of currently undeveloped resources that is consistent with the Government of Alberta's objective of maximizing recovery of known gas resources, while increasing royalty revenues. The policy's stated objective is for the mineral rights to shallow gas geological formations that are not being developed to revert back to the Government and be made available for resale, and in the event of non-productive shallow wells, to sever the rights from shallow zones and encourage increased production from up-hole zones. The shallow rights reversion policy affects all petroleum and natural gas agreements; however, the timing of the reversion will differ depending on the vintage of the leases and licenses and their location. Leases granted after January 1, 2009 will be subject to shallow rights reversion at the expiry of the primary term, and in the event of a licence the policy will apply at the expiry of the intermediate term. Holders of leases or licences that have been continued indefinitely prior to January 1, 2009 will receive a notice regarding the reversion of the shallow rights, which will be implemented three years from the date of the notice. The lease or licence holder can make a request to extend this period. The order in which these agreements will receive the reversion notice will depend on the vintage of their term, with the older leases and licenses receiving reversion notices first beginning in January 2011. Leases or licences that were granted prior to January 1, 2009 but have not yet been continued will have a grace period until they are continued under section 15 of the P&G Tenure Regulation and will be subject to deeper rights reversion prior to receiving a shallow rights reversion notice.

British Columbia

Producers of oil and natural gas in British Columbia are required to pay annual rental payments with respect to the Crown leases and royalties and freehold production taxes in respect of oil and gas produced from Crown and freehold lands, respectively. 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 calculation takes into account the production of oil on a well-by-well basis, the specified royalty rate for a given vintage of oil, the average unit selling price of the oil and any applicable royalty exemptions. Royalty rates are reduced on low productivity wells, reflecting the higher unit costs of extraction, and are the lowest for third-tier oil, reflecting the higher unit costs of both exploration and extraction.

The royalty payable on natural gas is determined by a sliding scale based on a reference price, which is the greater of the average net price obtained by the producer and a prescribed minimum price. When the reference price is below the select price (a parameter used in the royalty rate formula), the royalty rate is fixed. As an incentive for the production and marketing of natural gas, which may have been flared, natural gas produced in association with oil has a lower royalty than the royalty payable on non-conservation gas. A producer cost of service allowance is also deductible from the Crown royalty.

As at the beginning of 2009, British Columbia maintained a number of targeted royalty programs for key resource areas intended to increase the competitiveness of British Columbia's low productivity wells. These include both royalty credit and royalty reduction programs, including the following:

Summer Royalty Credit Program providing a royalty credit of 10 percent of drilling and completion costs up to $100,000 for wells drilled between April 1 and November 30 of each year, which is intended to increase summer drilling activity, employment and business opportunities in northeastern British Columbia;

Deep Royalty Credit Program providing a royalty credit equal to approximately 23 percent of drilling and completion costs for vertical wells with a true vertical depth greater than 2,500 metres and horizontal wells with a true vertical depth greater than 2,300 metres spud between December 1, 2003 and September 1, 2009;

Deep Re-Entry Royalty Credit Program providing royalty credits for deep re-entry wells with a true vertical depth greater than 2,300 metres and a re-entry date subsequent to December 1, 2003;

Deep Discovery Royalty Credit Program providing the lesser of a 3-year royalty holiday or 283,000,000 m3 of royalty free gas for deep discovery wells with a true vertical depth greater than 4,000 metres whose surface locations are at least 20 kilometres away from the surface location of any well drilled into a recognized pool within the same formation;

Coalbed Gas Royalty Reduction and Credit Program providing a royalty reduction for coalbed gas wells with average daily production less than 17,000 m3 as well as a royalty credit for coalbed gas wells equal to $50,000 for wells drilled on Crown land and a tax credit equal to $30,000 for wells drilled on freehold land;

Marginal Royalty Reduction Program providing royalty breaks for low productivity natural gas wells with average monthly production under 25,000 m3 during the first 12 production months and average daily production less than 23 m3 for every metre of marginal well depth;

Ultra-Marginal Royalty Reduction Program providing additional royalty reductions for low productivity shallow natural gas wells with a true vertical depth of less than 2,300 metres, average monthly production under 60,000 m3 during the first 12 production months, and average daily production less than 11.5 m3 (development wells) or 17 m3 (exploratory wildcat wells) for every 100 metres of marginal well depth; and

Net Profit Royalty Reduction Program providing reduced initial royalty rates to facilitate the development and commercialization of technically complex resources such as coalbed gas, tight gas, shale gas and enhanced-recovery projects, with higher royalty rates applied once capital costs have been recovered.

Oil produced from an oil well that is located on either Crown or freehold land and completed in a new pool discovered subsequent to June 30, 1974 may also be exempt from the payment of a royalty for the first 36 months of production or 11,450 m3 of production, whichever comes first.

On March 2, 2009, the Government of British Columbia announced the 2009 Infrastructure Royalty Credit Program (the "IRCP"), which allocates $120 million in royalty credits to oil and gas companies. The IRCP provides royalty credits for up to 50 percent of the cost of certain approved road construction or pipeline infrastructure projects intended to improve, or make possible, the access to new and underdeveloped oil and gas areas. The Government of British Columbia has recently announced the same level of funding for the 2010 IRCP.

On August 6, 2009, the Government of British Columbia announced an oil and gas stimulus package designed to attract investment in and create economic benefits for British Columbia. The stimulus package includes four royalty initiatives related primarily to natural gas drilling and infrastructure development. Natural gas wells spudded within the 10-month period from September 1, 2009 to June 30, 2010 and brought on production by December 31, 2010 qualify for a 2 percent royalty rate for the first 12 months of production, beginning from the first month of production for the well (the "Royalty Relief Program"). British Columbia's existing Deep Royalty Credit Program was permanently amended for wells spudded after August 31, 2009 by increasing the royalty deduction on deep drilling for natural gas by 15 percent and extending the program to include horizontal wells drilled to depths of between 1,900 and 2,300 metres. Wells spud between September 1, 2009 and June 30, 2010 may qualify for both the Royalty Relief Program and the Deep Royalty Credit Program but will only receive the benefits of one program at a time. An additional $50 million was also allocated to be distributed through the IRCP to stimulate investment in oilfield-related road and pipeline construction.

Saskatchewan

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

The Government of Saskatchewan currently provides a number of targeted incentive programs. These include both royalty reduction and incentive volume programs, including the following:

Royalty/Tax Incentive Volumes for Vertical Oil Wells Drilled on or after October 1, 2002 providing reduced Crown royalty and freehold tax rates on incentive volumes of 8,000 m3 for deep development vertical oil wells, 4,000 m3 for non-deep exploratory vertical oil wells, and 16,000 m3 for deep exploratory vertical oil wells (more than 1,700 metres or within certain formations);

Royalty/Tax Incentive Volumes for Exploratory Gas Wells Drilled on or after October 1, 2002 providing reduced Crown royalty and freehold tax rates on incentive volumes of 25,000,000 m3 for qualifying exploratory gas wells;

Royalty/Tax Incentive Volumes for Horizontal Oil Wells Drilled on or after October 1, 2002 providing reduced Crown royalty and freehold tax rates on incentive volumes of 6,000 m3 for non-deep horizontal oil wells and 16,000 m3 for deep horizontal oil wells (more than 1,700 metres or within certain formations);

Royalty/Tax Regime for Incremental Oil Produced from New or Expanded Waterflood Projects Implemented on or after October 1, 2002 treating incremental production from waterflood projects as fourth tier oil for the purposes of royalty calculation;

Royalty/Tax Regime for Enhanced Oil Recovery Projects (Excluding Waterflood Projects) Commencing prior to April 1, 2005 providing Crown royalty and freehold tax determinations based in part on the profitability of enhanced recovery projects pre-payout and post-payout; and

Royalty/Tax Regime for Enhanced Oil Recovery Projects (Excluding Waterflood Projects) Commencing on or after April 1, 2005 providing a Crown royalty of 1 percent of gross revenues on enhanced oil recovery projects pre-payout and 20 percent post-payout, and a freehold production tax of nil on operating income from enhanced oil recovery projects pre-payout and 8 percent post-payout.

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

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

Manitoba

In Manitoba, the royalty amount payable on oil produced from Crown lands depends on the classification of the oil produced as "old oil" (produced from a well drilled prior to April 1, 1974 that does not qualify as new oil or third tier oil), "new oil" (oil that is not third tier oil and is produced from a well drilled on or after April 1, 1974 and prior to April 1, 1999, from an abandoned well re-entered during that period, from an old oil well as a result of an enhanced recovery project implemented during that period, or from a horizontal well), "third tier oil" (oil produced from a vertical well drilled after April 1, 1999, an abandoned well re-entered after that date, an inactive vertical well activated after that date, a marginal well that has undergone a major workover, or from an old oil well or a new oil well as a result of an enhanced recovery project implemented after that date), or "holiday oil" (oil that is exempt from any royalty or tax payable). Royalty rates are calculated on a sliding scale and based on the monthly oil production from a spacing unit, or oil production allocated to a unit tract under a unit agreement or unit order from the Minister. For horizontal wells, the royalty on oil produced from Crown lands is calculated based on the amount of oil production allocated to a spacing unit in accordance with the applicable regulations.

Royalties payable on natural gas production from Crown lands are equal to 12.5 percent of the volume of natural gas sold.

Producers of oil and natural gas from freehold lands in Manitoba are required to pay monthly freehold production taxes. The freehold production tax payable on oil is calculated on a sliding scale based on the monthly production volume and the classification of oil as old oil, new oil, third tier oil and holiday oil. Producers of natural gas from freehold lands in Manitoba are required to pay a monthly freehold production tax equal to 1.2 percent of the volume sold. There is no freehold production tax payable on gas consumed as lease fuel.

The Government of Manitoba maintains a Drilling Incentive Program (the "Program") with the intent of promoting investment in the sustainable development of petroleum resources. The Program provides the licensee of newly drilled wells, or qualifying wells where a major workover has been completed, with a "holiday oil volume" pursuant to which no Crown royalties or freehold production taxes are payable until the holiday oil volume has been produced. Under the Program, wells drilled for purposes of injection (or wells converted to injection prior to producing predetermined volumes of oil) in an approved enhanced oil recovery project earn a one-year holiday for portions of the project area.

The Program consists of the following components:

New Well Incentive provides licensees of newly drilled, non-horizontal wells drilled prior to January 1, 2014 with a holiday oil volume of 10,000 m3;

Deep Drilling Incentive provides licensees who drill a well to a total depth sufficient to penetrate the Devonian Duperow formation with a holiday oil volume of 20,000 m3, and licensees who drill a well deeper than the Devonian Three Forks formation can make a one-time assignment of up to 10,000 m3 of holiday oil volume earned through previous drilling or major workovers to such well's holiday oil volume;

Horizontal Well Initiative provides licensees of horizontal wells drilled prior to January 1, 2014 with a holiday oil volume of 10,000 m3, and a horizontal leg drilled from an existing horizontal well on or after January 1, 2009 and prior to January 1, 2014 will earn an additional holiday royalty volume of 3,000 m3;

Marginal Well Major Workover Incentive provides licensees of marginal wells where a major workover is completed prior to January 1, 2014 with a holiday oil volume of 500 m3, with a marginal oil well defined as an abandoned well or a well that was either not operated over the previous 12 months or produced oil at an average rate of less than 1 m3 per operating day; and

Injection Well Incentive provides a one year exemption from the payment of Crown royalties or freehold production taxes on production allocated to a unit tract in which a well is drilled or converted to water injection.

Further, holiday oil volumes earned by a newly drilled well or a marginal well that has undergone a major workover can be transferred to a Holiday Oil Volume Account at the request of the licensee, the purpose of which is to optimize the value of holiday oil volumes earned by providing a company with the flexibility of allocating holiday oil volumes earned among new wells.

Land Tenure

Crude oil and natural gas located in the western provinces is owned predominantly by the respective provincial governments, with the exception of Manitoba, where approximately 80 percent of the crude oil and natural gas rights are not owned by the government. Provincial governments grant rights to explore for and produce oil and natural gas pursuant to leases, licences, and permits for varying terms, the minimum of which is two years, and on conditions set forth in provincial legislation, including requirements to perform specific work or make payments. Oil and natural gas located in such provinces can also be privately owned and rights to explore for and produce such oil and natural gas are granted by lease on such terms and conditions as may be negotiated.

Environmental Regulation

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

Alberta

Environmental legislation in Alberta has been consolidated into the Environmental Protection and Enhancement Act (Alberta) (the "EPEA"), which came into force on September 1, 1993, and the Oil and Gas Conservation Act (Alberta) (the "OGCA"). 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. The Climate Change and Emissions Management Amendment Act came into effect on July 1, 2007 ("CCEMAA") and was amended by the Climate Change and Emissions Management Amendment Act on November 4, 2008. Under this legislation, existing facilities in Alberta emitting more than 100,000 tonnes of greenhouse gases a year must reduce their emissions intensity by 12 percent. Industries have three options to choose from in order to meet the reduction requirements outlined in this legislation: (i) by making improvements to operations that result in reductions; (ii) by purchasing emission credits from non-regulated sectors or facilities that have emissions below the 100,000 tonne threshold and are voluntarily reducing their emission; or (iii) by contributing to the Climate Change and Emissions Management Fund (the "Fund"). Industries can either choose one of these options or a combination thereof. Pursuant to CCEMAA and the Specified Gas Emitters Regulation, companies were obliged to reduce their emission intensity by 12 percent by March 31, 2008. We do not operate any facilities in Alberta that are covered by this regulation. However, we do have minor working interests in non-operated facilities that are subject to the CCEMAA or the Specified Gas Emitters Regulation. Penn West's financial obligations associated with such non-operated facilities are not material.

In December 2008, the Government of Alberta released a new land use policy for surface land in Alberta, the Alberta Land Use Framework (the "ALUF"). The ALUF sets out an approach to manage public and private land use and natural resource development in a manner that is consistent with the long-term economic, environmental and social goals of the province. It calls for the development of region-specific land use plans in order to manage the combined impacts of existing and future land use within a specific region and the incorporation of a cumulative effects management approach into such plans. The Alberta Land Stewardship Act (the "ALSA") was proclaimed in force in Alberta on October 1, 2009, providing the legislative authority for the Government of Alberta to implement the policies contained in the ALUF. Regional plans established pursuant to the ALSA are deemed to be legislative instruments equivalent to regulations and are binding on the Government of Alberta and provincial regulators, including those governing the oil and gas industry. In the event of a conflict or inconsistency between a regional plan and another regulation, regulatory instrument or statutory consent, the regional plan will prevail. Further, the ALSA requires local governments, provincial departments, agencies and administrative bodies or tribunals to review their regulatory instruments and make any appropriate changes to ensure that they comply with an adopted regional plan. The ALSA also contemplates the amendment or extinguishment of previously issued statutory consents such as regulatory permits, licenses, approvals and authorizations in order to achieve or maintain an objective or policy resulting from the implementation of a regional plan. Among the measures to support the goals of the regional plans contained in the ALSA are conservation easements, which can be granted for the protection, conservation and enhancement of land; and conservation directives, which are explicit declarations contained in a regional plan to set aside specified lands in order to protect, conserve, manage and enhance the environment. Although no regional plans have been established under the ALSA, the planning process is underway for the Lower Athabasca Region (which contains the majority of oil sands development) and the South Saskatchewan Region. While the potential impact of the regional plans established under the ALSA cannot yet be determined, it is clear that such regional plans may have a significant impact on land use in Alberta and may affect the oil and gas industry.

British Columbia

British Columbia's Environmental Assessment Act became effective on June 30, 1995. This legislation rolls the previous processes for the review of major energy projects into a single environmental assessment process with public participation in the environmental review process. On February 27, 2007, the Government of British Columbia unveiled the Energy Plan outlining its strategy towards the environment, which includes targeting zero net greenhouse gas emissions, promoting new investments in innovation, and becoming the world's leader in sustainable environmental management. For this purpose, on December 18, 2007 proposals were sought for applications to the Innovative Clean Energy Fund, in order to attract new technologies that will help solve energy and environmental issues. With regards to the oil and natural gas industry the objective is to achieve clean energy through conservation and energy efficient practices, while competitiveness is advocated in order to attract investment for the development of the oil and natural gas sector. Among the changes to be implemented are: (i) a new Net Profit Royalty Program; (ii) the creation of a Petroleum Registry; (iii) the establishment of an infrastructure royalty program (combining roads and pipelines); (iv) the elimination of routine flaring at producing wells; (v) the creation of policies and measures for the reduction of emissions; (vi) the development of unconventional resources such as tight gas and coalbed gas; and (vii) the new Oil and Gas Technology Transfer Incentive Program that encourages the research, development and use of innovative technologies to increase recoveries from existing reserves and promotes responsible development of new oil and gas reserves.

In furtherance of the initiatives described above, on July 1, 2008 the Government of British Columbia introduced revenue-neutral carbon tax legislation that is applied to all fossil fuels used in the Province of British Columbia. The tax will be phased in: the initial rate was based on CO2 equivalent of $10 per tonne for the first six months of 2009 and $15 per tonne for the last six months of 2009, followed by $5 per tonne increases in July of every year until 2012. In 2009, Penn West paid approximately $1.4 million in carbon tax pursuant to this legislation with respect to its operated and non-operated properties in British Columbia.

On April 3, 2008, the Government of British Columbia introduced the Greenhouse Gas Reduction (Cap and Trade) Act (the "GGRA") which will allow participation in the Western Climate Initiative cap and trade system that is currently being developed. The system will establish a limit on emissions and will require regulated emitters to offset their emissions internally or buy/sell emission allowances. The emitter is obliged to obtain emission allowances (compliance units) equal to the amount of greenhouse gases emitted within a certain period of time, and that are supposed to be surrendered to the Government of British Columbia as proof of compliance. As the reduction requirements and compliance costs have not been established, we are currently unable to predict the impact of the GGRA on Penn West.

The Reporting Regulation, which was implemented under authority of the GGRA, was approved by Order of the Lieutenant Governor in Council on November 25, 2009. The regulation outlines the requirements for reporting operations within British Columbia emitting 10,000 tonnes or more of CO2 equivalent per year to report greenhouse gas emissions to the British Columbia Ministry of Environment. Those reporting operations with emissions of 25,000 tonnes or greater, which includes Penn West, are required to have emissions reports verified by a third party.

An accompanying Methodology Manual was released in December 2009 and outlines the requirements to comply with the Reporting Regulation. The Reporting Regulation does allow for an alternative methodology to be used for the 2010 reporting year. In conjunction with the Canadian Association of Petroleum Producers ("CAPP"), Penn West has applied for and been approved to use an alternative methodology which will eliminate some of the incremental reporting costs for 2010. The current regulations do not provide for an alternative reporting methodology after 2010. We are currently working with the Government of British Columbia and CAPP to better link the reporting goal to an appropriate financial burden on the oil and gas industry in 2011 and on onward.

Saskatchewan

On May 11, 2009, the Government of Saskatchewan announced The Management and Reduction of Greenhouse Gases Act (the "MRGGA") to regulate greenhouse gas emissions in the province. Although the MRGGA has only passed first reading in the Saskatchewan legislature and the specific details of the legislation have not yet been determined, it is expected that the MRGGA will adopt the goal of a 20% reduction in greenhouse gas emissions by 2020 and permit the use of technology fund contributions and emissions offsets in compliance, similar to both the federal and Alberta climate change initiatives. It remains unclear whether the scheme implemented by the MRGGA will be based on emissions intensity or an absolute cap on emissions.

Manitoba

The Government of Manitoba has recently indicated its intention to commence public consultations with respect to the development of a cap and trade system to reduce greenhouse gas emissions. No legislation with respect to climate change is currently in effect.

Federal

In December 2002, the Government of Canada ratified the Kyoto Protocol ("Kyoto Protocol"). The Kyoto Protocol calls for Canada to reduce its greenhouse gas emissions to six percent below 1990 "business-as-usual" levels between 2008 and 2012. Given revised estimates of Canada's normal emissions levels, this target translates into an approximately 40 percent gross reduction in Canada's current emissions. In December 2009, international climate change discussions were held in Copenhagen, Denmark to attempt to negotiate a successor to the Kyoto Protocol. The resulting "Copenhagen Accord" is not a legally binding agreement, but provides guiding principles related to global climate change issues. In response to the Copenhagen Accord, on January 29, 2010 the Government of Canada announced new emissions reduction targets of 17 percent from 2005 levels by 2020.

On April 26, 2007, the Government of Canada released "Turning the Corner: An Action Plan to Reduce Greenhouse Gases and Air Pollution" (the "Action Plan") which set forth a plan for regulations to address both greenhouse gases and air pollution. An update to the Action Plan, "Turning the Corner: Regulatory Framework for Industrial Greenhouse Gas Emissions" was released on March 10, 2008 (the "Updated Action Plan"). Although draft regulations for the implementation of the Updated Action Plan were intended to be published in the fall of 2008 and become binding on January 1, 2010, no such regulations have been proposed to date. Further, representatives of the Government of Canada have recently indicated that the proposals contained in the Updated Action Plan will be modified to ensure consistency with the direction ultimately taken by the United States with respect to greenhouse gas emissions regulation. The approach of the Unites States is expected to include an absolute cap on emissions combined with allowances to be used for compliance that may be partially auctioned off to regulated entities. It is also unclear whether the approach adopted by the United States will provide for the payment into a technology fund as a compliance mechanism, as is currently permitted in Alberta and by the Updated Action Plan. As a result, many provisions of the Updated Action Plan, described below, are expected to be significantly modified.

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

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

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

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

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

Penn West and the Environment

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

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

We maintain a program of detailed inspections, audits and field assessments to determine and quantify the environmental liabilities that will be incurred during the eventual decommissioning and reclamation of our field facilities. We pursue a program of environmental impact reduction aimed at minimizing these future corporate liabilities without hampering field productivity. This program, launched in 1994 and ongoing into 2010, includes measures to remediate potential contaminant sources, reclaim spill sites and abandon unproductive wells and shut-in facilities. We have implemented strategies to reduce greenhouse gas emissions and flaring and continued the program to test CO2 enhanced oil recovery methods, which would "sequester" CO2 in hydrocarbon reservoirs.

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

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

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

During 2009, we continued our pilot-scale CO2 injection programs in the Pembina and Swan Hills areas of Alberta. If successful, the pilot projects could lead to a much larger enhanced oil recovery program with the potential to sequester significant volumes of CO2. We also continued numerous discussions with various parties regarding the development of a cost effective system to supply and deliver commercial amounts of CO2 to our fields that are candidates for CO2 injection.

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

RISK FACTORS

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

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

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

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

political instability and hostilities and the risk of hostilities;

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

weather conditions;

the overall level of energy demand;

production and storage levels of natural gas;

government regulations and taxes;

currency exchange rates;

the availability of transportation infrastructure;

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

the price and availability of alternative energy supplies; and

the overall economic environment.

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

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

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

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

The global financial crisis and severe recession experienced in 2008 and 2009 has had (and may continue to have) an adverse effect on commodity prices and has had (and may continue to have) an adverse effect on our access to capital, one or both of which could have a material adverse effect on our results of operations and financial condition, which in turn could negatively affect the amount of distributions paid to our Unitholders.

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

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

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

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

At March 18, 2010, we had approximately $1.3 billion of unused credit available under our credit facilities. Based on current funds available and expected cash from operations, we believe that we have sufficient funds available to fund our projected capital expenditures. However, if cash flow from operations is lower than expected or capital costs for these projects exceeds current estimates, or if we incur major unanticipated expenses related to development or maintenance of our existing properties, we may be required to seek additional capital to maintain our capital expenditures at planned levels. Failure to obtain financing necessary for our capital expenditure plans may result in a delay in development or production on our properties and/or a decrease in distributions.

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

We currently have a credit facility in place that has an aggregate borrowing limit of $3.25 billion and a maturity date of January 11, 2011 (which is extendible with lender approval). As of March 18, 2010, approximately $2.0 billion was outstanding under our credit facility. In the event that our credit facility is not extended before January 11, 2011, all outstanding indebtedness thereunder will be repayable at that date. There is also a risk that our credit facility will not be renewed for the same principal amount or on the same terms. Any of these events could adversely affect our ability to fund our ongoing operations and, as repayment of such indebtedness has priority over the payment of cash distributions to Unitholders, to distribute cash to Unitholders.

We also currently have: (i) U.S.$475 million principal amount of 2007 Senior Notes outstanding which require principal repayments starting in May 2015 and continuing until May 2022; (ii) U.S.$480 million and Cdn$30 million principal amount of 2008 Senior Notes outstanding which require principal repayments starting in May 2016 and continuing until May 2020; (iii) £57 million principal amount of 2008 Pounds Sterling Senior Notes outstanding which require principal repayment in July 2018; (iv) US$154 million, £20 million, €10 million and Cdn$5 million principal amount of 2009 Senior Notes outstanding which require principal payments starting in May 2014 and continuing until May 2019; (v) US$250 million and Cdn$50 million principal amount of 2010 Senior Notes outstanding which require principal payments starting in March 2015 and continuing until March 2025; and (vi) $273 million principal amount of Convertible Debentures outstanding which require principal repayments starting June 30, 2010 and continuing until December 2011. In the event we are unable to repay or refinance these debt obligations it may adversely affect our ability to fund our ongoing operations and, as repayment of such indebtedness has priority over the payment of cash distributions to Unitholders, to distribute cash to Unitholders.

We are required to comply with covenants under our credit facilities, the 2007 Senior Notes, the 2008 Senior Notes, the 2008 Pounds Sterling Senior Notes, the 2009 Senior Notes and the 2010 Senior Notes. In the event that we do not comply with covenants under one or more of these debt instruments, our access to capital could be restricted or repayment could be required, which could adversely affect our ability to fund our ongoing operations and, as repayment of such indebtedness has priority over the payment of cash distributions to Unitholders, to distribute cash to Unitholders.

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

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

resources, including capital and skilled personnel;

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

access to equipment, markets, transportation capacity, drilling and service rigs and processing facilities.

In our view, the SIFT Tax imposed by the Government of Canada has made our Trust Units less attractive as consideration for acquisitions. As a result of such increasing competition, it has become (and we expect it to continue to be) more difficult to acquire producing assets and reserves on accretive terms. We also compete for skilled industry personnel with a substantial number of other oil and gas companies and trusts.

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

historical production from the properties;

estimated production decline rates;

ultimate estimated reserve recovery;

changes in technology;

timing and amount and effectiveness of future capital expenditures;

marketability and price of oil and natural gas;

royalty rates;

the assumed effects of regulation by governmental agencies; and

future operating costs;

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

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

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

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

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

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

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

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

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

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

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

In light of the economic and commodity price environment in the latter half of 2008, we reduced our 2009 capital expenditure budget and our 2009 monthly distribution to Unitholders significantly from 2008 levels, in each case in an effort to reduce debt levels and position ourselves to capitalize on acquisition opportunities. Our 2010 capital expenditure budget and our current monthly distribution to Unitholders continue to be significantly below 2008 levels for the same reasons. There are certain risks associated with this strategy, including that: (i) reduced capital spending will decrease future production and cash flow available for distributions; (ii) reducing cash distributions to Unitholders may reduce the trading price or value of the Trust Units in the market; and (iii) we may not be able to execute an attractive acquisition. In addition, we may be required to further revise our strategy in the future, and any further changes may adversely affect the cash distributions to Unitholders or the value or trading price of the Trust Units.

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

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

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

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

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

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

The SIFT Tax provides that, while there is no intention to prevent "normal growth" during the transitional period, any "undue expansion" would result in the transition period being terminated with the loss of the benefit to us of that transitional period. As a result, the adverse tax consequences resulting from the SIFT Tax could be borne sooner than January 1, 2011. On December 15, 2006, the Department of Finance issued guidelines with respect to what is meant by "normal growth" in this context. Specifically, the Department of Finance stated that "normal growth" would include equity growth within certain "safe harbour" limits, measured by reference to a SIFT's market capitalization as of the end of trading on October 31, 2006 (which would include only the market value of the SIFT's issued and outstanding publicly-traded trust units, and not any convertible debt, options or other interests convertible into or exchangeable for trust units). Those safe harbour limits are 40 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: (i) new equity for these purposes includes units and debt that is convertible into units (and may include other substitutes for equity if attempts are made to develop those); and (ii) replacing debt that was outstanding as of October 31, 2006 with new equity, whether by a conversion into trust units of convertible debentures or otherwise, will not be considered growth for these purposes and will therefore not affect the safe harbour.

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

The Department of Finance has also indicated that a SIFT's market capitalization for the purpose of calculating a SIFT's "safe harbour" equity growth limit is equal to the aggregate market capitalization of the SIFT and all SIFTs acquired by such SIFT as of the end of trading on October 31, 2006. The combined market capitalization of the Trust, Canetic and Vault as of the close of trading on October 31, 2006, having regard only to the issued and outstanding publicly-traded Trust Units and Canetic and Vault trust units at such date, was approximately $15 billion. We believe that, as at March 18, 2010, our remaining combined "safe harbour" equity growth amount for the period ending December 31, 2010 is approximately $14 billion (not including equity, including convertible debentures, issued to replace debt that was outstanding on October 31, 2006). These guidelines may adversely affect the cost of raising capital and our ability to undertake significant acquisitions. Although the SIFT Tax is not expected to effect the Trust until 2011, the Trust could become subject to the trust-level tax sooner if it experiences growth other than "normal growth" before then.

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

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

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

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

As a result of the above-described changes to the taxation of income trusts, we currently plan to convert to a dividend paying corporation prior to mid-2011. The timing of such conversion is dependent on a number of factors, including without limitation the strength of commodity prices and the equity markets, our operating performance, and the extent of our success in developing our inventory of prospects. We are currently hesitant to make structural changes prior to the end of 2010 unless opportunities arise, as we believe this exemption period has value for our Unitholders. Even if we do not convert to a corporation or other form of entity prior to mid-2011, it is likely that such a conversion would be completed prior to January 1, 2013 in order to effect the conversion without undue tax consequences for Penn West or its Unitholders. As discussed in more detail above, Bill C-10, which received Royal Assent on March 12, 2009, contained legislation implementing the SIFT Conversion Rules which facilitate the conversion of existing SIFTs into corporations on a tax-deferred basis. Unless circumstances change within the current capital markets or the regulatory, tax or political environment, we currently believe that we will most likely convert into a dividend paying corporation. If we do complete a conversion to a corporate or other form of structure, the nature of a Unitholder's investment will change, and the conversion may adversely impact some or all of our Unitholders. Although at this time we believe that such a conversion may be completed without creating a taxable event for most Unitholders for Canadian and U.S. federal income tax purposes, no assurance can be given that such a conversion will not give rise to income tax liability. However, going forward, there can be no assurance that the taxation of future payments received from us in a corporate or other form will not give rise to tax consequences that are more adverse to securityholders than the current treatment of distributions to our Unitholders, and may differ depending on the Unitholder's tax jurisdiction and whether the Unitholder is holding its investment in a taxable or tax-deferred account. Following the completion of any such conversion, we will be subject to additional risk factors that are relevant to the form of entity into which we convert.

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

For additional information on the SIFT Tax, including its potential impact on us and our Unitholders and the actions that we might take in response to the SIFT Tax (including with respect to our anticipated tax horizon), see the following: "General Development of the Business – History and Development – Year Ended December 31, 2006 – Changes to Taxation of Income Trusts" in this Annual Information Form; "Other Oil and Gas Information – Tax Horizon" in Appendix A-3 to this Annual Information Form; and "Update on SIFT Tax and Corporate Conversion" set forth in our management's discussion and analysis for the year ended December 31, 2009 (available on SEDAR at www.sedar.com and on EDGAR at www.sec.gov).

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

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

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

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

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

We may be subject to growth related risks, including capacity constraints and pressures on our internal systems and controls. These constraints and pressures could result from, among other things, the completion of large acquisitions. Our ability to manage growth effectively will require us to continue to implement and improve our operational and financial systems and to expand, train and manage our employee base. Our inability to deal with this growth could have a material adverse impact on our business, operations and prospects.

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

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

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

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

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

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

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

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

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

Acquiring, exploring for and developing oil and natural gas assets involves many risks. These risks include, but are not limited to:

encountering unexpected formations or pressures;

premature declines of reservoirs;

blow-outs, equipment failures and other accidents;

sour gas releases;

uncontrollable flows of oil, natural gas or well fluids;

adverse weather conditions; and

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

The limited liability of Unitholders is uncertain.

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

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

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

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

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

Penn West utilizes new drilling and completion technologies, including horizontal multi-fracture completions, intended to increase the resource recovery from known producing oil and natural gas fields. There is potential Penn West may not realize the anticipated increase in resource recovery from the employment of such techniques due to particular reservoir characteristics or other adverse factors. The potential or planned use of enhanced oil recovery ("EOR") methods such as steam injection (Steam Assisted Gravity Drainage, Cyclical Steam Stimulation and Steam Flooding), solvent injection and firefloods to increase the ultimate recovery of oil resources in place are subject to significant risk factors. These factors include but are not limited to the following:

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

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

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

surface access and deliverability issues (including landowner and stakeholder relations, weather, pipeline, road and processing matters);

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

the availability of sufficient financing on acceptable terms.

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

the existence of commercial scale CO2 supply and infrastructure (including the ability to capture and transport the miscible agent to us at an economic cost);

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

changing engineering and technical conditions (including the ability to apply CO2 EOR methods to the reservoir and the production response thereto);

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

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

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

the availability of sufficient financing on acceptable terms;

changing regulatory frameworks, which could impact our long term storage liability and our monitoring, measurement and verification costs on CO2 miscible flood projects;

changing royalty structures which may impact CO2 flood economics; and

the potential for out-of-zone and wellbore leakage which could delay or cause the cancellation of some or all of these projects.

Unitholders may suffer dilution.

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

Unitholders may also suffer dilution as a result of the issuance of Trust Units pursuant to our Trust Unit Rights Incentive Plan (“TURIP”), Employee Retirement Savings Plan (“ERSP”) and Distribution Reinvestment and Optional Trust Unit Purchase Plan (“DRIP”). For more information regarding the TURIP and the ERSP, see our most recent Information Circular and Proxy Statement filed on SEDAR at www.sedar.com. For more information regarding our DRIP, see Note 11 to our audited consolidated financial statements for the year ended December 31, 2009, which is filed on SEDAR at www.sedar.com.

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

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

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

In order for us to maintain our status as a mutual fund trust under the Tax Act, we must not be established or maintained primarily for the benefit of Non-Residents unless we satisfy the requirements of certain exceptions. The Trust Indenture provides that we will use our best commercial efforts to maintain our status as a mutual fund trust under the Tax Act. Generally speaking, the Tax Act provides that a trust will permanently lose its "mutual fund trust" status (which is essential to the income trust structure) if it is established or maintained primarily for the benefit of Non-Residents (which is generally interpreted to mean that the majority of unitholders must not be Non-Residents), unless at the relevant time, "all or substantially all" of the trust's property consists of property other than taxable Canadian property (the "TCP Exception"). Based on information obtained by us through our transfer agent and financial intermediaries, as of February 2010, we estimate that approximately 66 percent of our issued and outstanding Trust Units were held by Non-Residents. We have determined that we currently meet the requirement of the TCP Exception, and as a result, the Trust Indenture does not currently have a specific limit on the percentage of Trust Units that may be owned by Non-Residents.

There is no assurance that the TCP Exception will continue to be available to us or that the Government of Canada will not introduce new changes or proposals to tax regulations directed at Non-Resident ownership which, given our level of Non-Residents ownership, may result in us losing our mutual fund trust status or could otherwise detrimentally affect us and the market price of the Trust Units.

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

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

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

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

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

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

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

If the loss of mutual fund trust status was likely, we would accelerate our plan to convert to a corporation.

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

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

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

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

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

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

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

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

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

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

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

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

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

The primary differences between the United States requirements and the NI 51-101 requirements are that (i) the U.S. standards require disclosure only of proved reserves, whereas NI 51-101 requires disclosure of proved and probable reserves, and (ii) the U.S. standards require that the reserves and related future net revenue be estimated using a historic constant price, whereas NI 51-101 requires disclosure of reserves and related future net revenue using forecast prices. In addition, under U.S. disclosure standards, reserves and production information is disclosed on a net basis (after royalties), whereas in Canada such information is disclosed on a gross basis.

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

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

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

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

Under U.S. GAAP, the estimated recoverable amounts are calculated based on estimated future net funds flows from proved reserves discounted at ten percent and using the average of commodity prices on the first day of each month of the preceding year. The use of discounting and constant prices results in a greater likelihood of a write-down under U.S. GAAP than Canadian GAAP.

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

Canadian GAAP requires that goodwill balances be assessed at least annually for impairment and that any permanent impairment be charged to net income. A permanent reduction in reserves, decline in commodity prices, and/or reduction in the Trust Unit price may indicate goodwill impairment. As at December 31, 2009, we had approximately $2 billion recorded on our balance sheet as goodwill arising primarily out of the Petrofund Acquisition and the Canetic Acquisition. An impairment would result in a write-down of the goodwill value and a non-cash charge against net income. The calculation of impairment value is subject to management estimates and assumptions.

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

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

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

United States Unitholders (meaning, for the purposes of this section, tax residents for United States federal income tax purposes as defined under Section 7701 of the United States Internal Revenue Code, as amended (the "Code")) should be aware that the United States Internal Revenue Service may determine that the Trust is a "passive foreign investment company" (a "PFIC") under Section 1297(a) of the Code for the 2009 taxable year and in subsequent taxable years. The Trust will be a PFIC if at least 75 percent of its income consists of dividends, interest, and other passive items or if 50 percent or more of the average value of its assets (on a gross value basis) consist of assets that would produce passive income. In determining whether it is a PFIC, a foreign corporation is required to take into account a pro rata portion of the income and assets of each corporation in which it owns, directly or indirectly, at least a 25 percent interest. To date, we have received advice that the Trust should not be considered a PFIC for the years 2002 through 2009, and we do not expect to be considered a PFIC for 2010.

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

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

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

Trust Units will have no value when the underlying petroleum and natural gas properties can no longer be economically produced and, as a result, cash distributions may not represent a "yield" in the traditional sense and are not comparable to bonds or other fixed yield securities, where investors are entitled to a full return of the principal amount of debt on maturity in addition to a return on investment through interest payments. Distributions can represent a return of or a return on Unitholders' capital.

Your redemption right as a Unitholder is limited.

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

MATERIAL CONTRACTS

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

(a)

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

(b)

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

(c)

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

(d)

the credit agreement dated January 10, 2008 among PWPL and certain lenders and other parties in respect of Penn West's $3.25 billion syndicated credit facility, which agreement is described in Note 6 to Penn West's consolidated financial statements for the year ended December 31, 2009, which note is incorporated by reference herein;

(e)

the note purchase agreement dated May 31, 2007 among PWPL and the holders of the 2007 Senior Notes, which agreement is described in Note 6 to Penn West's consolidated financial statements for the year ended December 31, 2009, which note is incorporated by reference herein. See also "General Development of the Business – History and Development - Year Ended December 31, 2007 – Private Placement of 2007 Senior Notes";

(f)

the note purchase agreement dated May 29, 2008 among PWPL and the holders of the 2008 Senior Notes, which agreement is described in Note 6 to Penn West's consolidated financial statements for the year ended December 31, 2009, which note is incorporated by reference herein. See also "General Development of the Business – History and Development - Year Ended December 31, 2008 – Private Placement of 2008 Senior Notes";

(g)

the note purchase agreement dated July 31, 2008 among PWPL and the holders of the 2008 Pounds Sterling Senior Notes, which agreement is described in Note 6 to Penn West's consolidated financial statements for the year ended December 31, 2009, which note is incorporated by reference herein. See also "General Development of the Business – History and Development - Year Ended December 31, 2008 – Private Placement of 2008 Pounds Sterling Senior Notes";

(h)

the note purchase agreement dated May 5, 2009 among PWPL and the holders of the 2009 Senior Notes, which agreement is described in Note 6 to Penn West's consolidated financial statements for the year ended December 31, 2009, which note is incorporated by reference herein. See also "General Development of the Business – History and Development - Year Ended December 31, 2009 – Private Placement of 2009 Senior Notes"; and

(i)

the note purchase agreement dated March 16, 2010 among PWPL and the holders of the 2010 Senior Notes, which agreement is described in Note 20 to Penn West's consolidated financial statements for the year ended December 31, 2009, which note is incorporated by reference herein. See also "General Development of the Business – History and Development – 2010 Developments – Private Placement of 2010 Senior Notes".

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

LEGAL PROCEEDINGS AND REGULATORY ACTIONS

There are no legal proceedings that Penn West is or was a party to, or that any of Penn West's property is or was the subject of, during the most recently completed financial year, that were or are material to Penn West, and there are no such material legal proceedings that Penn West knows to be contemplated. For the purposes of the foregoing, a legal proceeding is not considered to be "material" by us if it involves a claim for damages and the amount involved, exclusive of interest and costs, does not exceed 10 percent of our current assets, provided that if any proceeding presents in large degree the same legal and factual issues as other proceedings pending or known to be contemplated, we have included the amount involved in the other proceedings in computing the percentage.

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

TRANSFER AGENTS AND REGISTRARS

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

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

INTEREST OF MANAGEMENT AND OTHERS IN MATERIAL TRANSACTIONS

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

INTERESTS OF EXPERTS

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

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

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

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

ADDITIONAL INFORMATION

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

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

APPENDIX A-1

REPORT OF MANAGEMENT AND DIRECTORS ON RESERVES DATA AND OTHER INFORMATION

(Form 51-101F3)

Management of Penn West Petroleum Ltd. ("PWPL"), on behalf of Penn West Energy Trust (together with PWPL, "Penn West"), is responsible for the preparation and disclosure of information with respect to Penn West's oil and gas activities in accordance with securities regulatory requirements. This information includes reserves data which are estimates of proved reserves and probable reserves and related future net revenue as at December 31, 2009, estimated using forecast prices and costs.

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

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

(a)

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

(b)

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

(c)

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

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

(a)

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

(b)

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

(c)

the content and filing of this report.

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

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

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

March 18, 2010

APPENDIX A-2

REPORT ON RESERVES DATA

(Form 51-101 F2)

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

1.	We have evaluated (or in some cases audited) Penn West's reserves data as at December 31, 2009. The reserves data are estimates of proved reserves and probable reserves and related future net revenue as at December 31, 2009, estimated using forecast prices and costs.

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

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

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

The following table sets forth the estimated future net revenue (before deduction of income taxes) attributed to proved plus probable reserves, estimated using forecast prices and costs and calculated using a discount rate of 10 percent, included in the reserves data of Penn West evaluated and audited by us for the year ended December 31, 2009, and identifies the respective portions thereof that we have evaluated and audited and reported on to PWPL's Board of Directors:

Independent Qualified Reserves Evaluator or Auditor	Description and Preparation Date of Evaluation / Audit Report	Location of Reserves	Net Present Value of Future Net Revenue (millions before income taxes, 10% discount rate)
Independent Qualified Reserves Evaluator or Auditor		Location of Reserves	Audited		Evaluated		Reviewed		Total
GLJ Petroleum Consultants Ltd.	February 11, 2010	Canada	$	-	$	5,537	$	-	$	5,537
Sproule Associates Limited	February 24, 2010	Canada	$	1,735	$	4,312	$	-	$	6,047
Sproule Associates Limited	February 24, 2010	USA	$	-	$	39	$	-	$	39

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

7.	We have no responsibility to update our reports referred to in paragraph 5 for events and circumstances occurring after their respective preparation dates.

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

Executed as to our report referred to above:

(signed) GLJ Petroleum Consultants Ltd.

Calgary, Alberta, Canada

March 18, 2010

(signed) Sproule Associates Limited

Calgary, Alberta, Canada

March 18, 2010

APPENDIX A-3

STATEMENT OF RESERVES DATA AND OTHER OIL AND GAS INFORMATION

Our statement of reserves data and other oil and gas information is set forth below (the "Statement"). The effective date of the Statement is December 31, 2009 and the preparation date of the Statement is March 18, 2010. The Report of Management and Directors on Reserves Data and Other Information on Form 51-101F3 and the Report on Reserves Data by GLJ and Sproule on Form 51-101F2 are attached as Appendices A-1 and A-2, respectively, to this Annual Information Form.

Disclosure of Reserves Data

The reserves data set forth below is based upon: (i) an evaluation prepared by GLJ with an effective date of December 31, 2009 contained in the GLJ Report dated February 11, 2010; and (ii) an evaluation and audit prepared by Sproule with an effective date of December 31, 2009 contained in the Sproule Report dated February 24, 2010. The reserves data summarizes our oil, natural gas liquids and natural gas reserves and the net present values of future net revenue from these reserves using forecast prices and costs, not including the impact of any hedging activities. The reserves data conforms with the requirements of NI 51-101. We engaged GLJ to evaluate approximately 45 percent of our proved and proved plus probable reserves. We engaged Sproule to evaluate approximately 36 percent and to audit approximately 19 percent of our proved and proved plus probable reserves. See also "Notes to Reserve Data Tables" below.

On March 11, 2010, the Alberta government announced changes to Alberta's royalty regime that are intended to increase Alberta's competitiveness in the oil and natural gas industry. The changes included a decrease in the maximum royalty rates for conventional oil and natural gas production effective for the January 2011 production month. In addition, certain temporary incentive programs currently in place will be made permanent. Further details with respect to the changes to Alberta's royalty regime are expected to be provided in the coming months. See "Industry Conditions". Reserves and net present values reflected in this Annual Information Form (including in the tables set out below) do not reflect the potential effect of these new changes to Alberta's royalty regime and no sensitivities were provided by GLJ and Sproule as to the potential impact of same.

The majority of our proved plus probable reserves are located in Canada in the provinces of Alberta, British Columbia, Saskatchewan and Manitoba, and in the Northwest Territories. We also have minor proved plus probable reserves interests in the United States in the States of Montana, Wyoming and North Dakota. The reserves information presented below does not report reserves that are located in the United States separately. Our properties located in the United States have proved plus probable gross reserves of approximately 3 MMboe, which represents less than one percent of our total proved plus probable reserves, and have a before tax net present value discounted at 10 percent of approximately $39 million, which represents less than one percent of the total value of our proved plus probable reserves.

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

Reserves Data (Forecast Prices and Costs)

SUMMARY OF OIL AND GAS RESERVES

as of December 31, 2009

FORECAST PRICES AND COSTS

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

PROVED
Developed Producing		211		181		53		48
Developed Non-Producing		4		3		1		1
Undeveloped		46		40		2		1
TOTAL PROVED		261		224		56		51

PROBABLE		107		91		15		13
TOTAL PROVED PLUS PROBABLE		368		316		71		64

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

PROVED
Developed Producing		828		713		22		16
Developed Non-Producing		49		39		1		1
Undeveloped		61		54		1		1
TOTAL PROVED		938		807		24		17

PROBABLE		354		299		9		6
TOTAL PROVED PLUS PROBABLE		1,292		1,105		33		24

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

PROVED
Developed Producing		423		364
Developed Non-Producing		14		12
Undeveloped		59		51
TOTAL PROVED		497		426

PROBABLE		190		161
TOTAL PROVED PLUS PROBABLE		687		587

NET PRESENT VALUES OF FUTURE NET REVENUE

BEFORE INCOME TAXES DISCOUNTED AT (%/year)

FORECAST PRICES AND COSTS

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

PROVED
Developed Producing		14,235		10,092		7,913		6,572		5,658		21.76		3.63
Developed Non-Producing		411		309		245		203		173		21.08		3.51
Undeveloped		2,417		1,345		830		541		362		16.22		2.70
TOTAL PROVED		17,063		11,746		8,989		7,315		6,193		21.08		3.51

PROBABLE		8,461		4,294		2,635		1,802		1,321		16.38		2.73

TOTAL PROVED PLUS PROBABLE		25,524		16,040		11,623		9,118		7,513		19.79		3.30

Note:

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

NET PRESENT VALUES OF FUTURE NET REVENUE

AFTER INCOME TAXES DISCOUNTED AT (%/year)

FORECAST PRICES AND COSTS

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

PROVED
Developed Producing		12,505		9,158		7,340		6,192		5,394
Developed Non-Producing		306		236		191		162		140
Undeveloped		1,778		982		597		379		244
TOTAL PROVED		14,589		10,376		8,128		6,733		5,778

PROBABLE		6,116		3,109		1,908		1,306		958

TOTAL PROVED PLUS PROBABLE		20,705		13,485		10,037		8,039		6,736

TOTAL FUTURE NET REVENUE

(UNDISCOUNTED)

as of December 31, 2009

FORECAST PRICES AND COSTS

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

Proved Reserves		40,793		6,085		15,417		1,152		1,076		17,063		2,474		14,589
Proved Plus Probable Reserves		58,289		8,900		20,731		1,915		1,219		25,524		4,819		20,705

FUTURE NET REVENUE

BY PRODUCTION GROUP

as of December 31, 2009

FORECAST PRICES AND COSTS

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

Proved Reserves	Light and Medium Crude Oil(1)		6,832		21.06		3.51
	Heavy Oil(1)		1,199		22.02		3.67
	Natural Gas(2)		888		21.52		3.59
	Non-Conventional Oil and Gas Activities		70		10.90		1.82
	TOTAL		8,989		21.08		3.51

Proved Plus Probable Reserves	Light and Medium Crude Oil(1)		8,993		19.80		3.30
	Heavy Oil(1)		1,452		21.12		3.52
	Natural Gas(2)		1,077		19.75		3.29
	Non-Conventional Oil and Gas Activities		101		10.33		1.72
	TOTAL		11,623		19.79		3.30

Notes:

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

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

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

Notes to Reserves Data Tables

1.	Columns may not add due to rounding.

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

Reserves Categories

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

(a)

analysis of drilling, geological, geophysical and engineering data;

(b)

the use of established technology; and

(c)

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

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

(d)

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

(e)

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

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

Development and Production Status

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

(f)

Developed reserves are those reserves that are expected to be recovered from existing wells and installed facilities or, if facilities have not been installed, that would involve a low expenditure (for example, when compared to the cost of drilling a well) to put the reserves on production. The developed category may be subdivided into producing and non-producing.

(i)

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

(ii)

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

(g)

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

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

Levels of Certainty for Reported Reserves

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

(a)

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

(b)

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

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

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

3.	Forecast prices and costs

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

The forecast cost and price assumptions include increases in wellhead selling prices and take into account inflation with respect to future operating and capital costs. Crude oil, natural gas and natural gas liquids benchmark reference pricing, as at December 31, 2009, inflation and exchange rates utilized in the Engineering Reports were as set forth below. The price assumptions set forth below were provided by GLJ and Sproule.

SUMMARY OF PRICING AND INFLATION RATE ASSUMPTIONS

as of December 31, 2009

FORECAST PRICES AND COSTS

	OIL															EDMONTON LIQUIDS PRICES
Year	WTI Cushing Oklahoma ($US/bbl)			Edmonton Par Price 40ºAPI ($Cdn/bbl)			Lloydminster Blend 21ºAPI ($Cdn/bbl)			Cromer Medium 29.3ºAPI ($Cdn/bbl)			NATURAL GAS AECO ($Cdn/Mcf)			Propane ($Cdn/bbl)			Butane ($Cdn/bbl)			Pentanes Plus ($Cdn/bbl)			INFLATION RATES(1) %/year			EXCHANGE RATE(2) ($US equals $1.00 Cdn)
Forecast
2010		79.58			83.75			72.25			78.32			5.66			52.60			61.88			85.61			-			0.94
2011		83.73			88.20			74.79			81.61			6.50			55.39			65.13			90.15			2	%		0.94
2012		86.45			91.09			74.49			82.91			6.67			57.20			67.28			93.11			2	%		0.94
2013		89.60			94.46			75.84			85.04			7.09			59.32			69.76			96.55			2	%		0.94
2014		92.00			97.01			77.38			86.83			7.52			60.93			71.66			99.16			2	%		0.94
2015		93.84			98.98			78.94			88.59			7.66			62.16			73.11			101.16			2	%		0.94
2016		95.72			100.97			80.54			90.37			7.88			63.41			74.58			103.20			2	%		0.94
2017		97.64			103.01			82.16			92.20			8.24			64.69			76.09			105.29			2	%		0.94
2018		99.59			105.09			83.83			94.06			8.62			66.00			77.63			107.41			2	%		0.94
2019		101.58			107.21			85.51			95.96			8.80			67.33			79.19			109.58			2	%		0.94
Thereafter		2	%		2	%		2	%		2	%		2	%		2	%		2	%		2	%		2	%		0.94

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, 2009 were $4.82/Mcf for natural gas, $71.22/bbl for light and medium crude oil, $53.75/bbl for heavy oil and $41.07/bbl for natural gas liquids.

4.	Future Development Costs

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

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

2010		342		448
2011		302		453
2012		143		349
2013		85		215
2014		49		106
Total: Undiscounted for all years		1,152		1,915

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

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

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

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

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

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

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

Reconciliations of Changes in Reserves

The following table sets forth the reconciliation of our gross reserves as at December 31, 2009, using forecast price and cost estimates derived from the Engineering Reports.

RECONCILIATION OF

COMPANY GROSS RESERVES

BY PRODUCT TYPE

FORECAST PRICES AND COSTS

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

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

Extensions		12			21			34			-			-			-			21			8			29
Improved Recovery(1)		7			-			6			2			-			2			4			1			5
Technical Revisions		1			(5	)		(4	)		11			(3	)		8			24			(38	)		(14	)
Discoveries		-			-			-			-			-			-			2			1			4
Acquisitions		4			2			6			-			-			-			8			4			12
Dispositions		(1	)		-			(2	)		(11	)		(14	)		(24	)		(37	)		(17	)		(55	)
Economic Factors		-			-			-			-			-			-			(1	)		(9	)		(10	)
Production		(24	)		-			(24	)		(10	)		-			(10	)		(157	)		-			(157	)

December 31, 2009		261			107			368			56			15			71			938			354			1,292

Note:

(1)	Improved recovery includes the following infill drilling:

Infill Drilling

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

December 31, 2008		27			9			37			532			197			729

Extensions		1			-			1			16			23			39
Improved Recovery(1)		-			-			-			9			-			10
Technical Revisions		-			(1	)		-			17			(15	)		2
Discoveries		-			-			-			-			-			1
Acquisitions		-			-			-			5			3			8
Dispositions		(1	)		-			(1	)		(19	)		(17	)		(36	)
Economic Factors		-			-			-			-			(2	)		(2	)
Production		(4	)		-			(4	)		(64	)		-			(64	)

December 31, 2009		24			9			33			497			190			687

Notes:

(1)	Improved recovery includes the following infill drilling:

Infill Drilling

(2)	Columns may not add due to rounding.

Additional Information Relating to Reserves Data

Undeveloped Reserves

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

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

Proved Undeveloped Reserves

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

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

Prior thereto		33,447		33,447		1,839		1,839		43,433		43,433		1,452		1,452
2007		5,313		34,496		636		1,041		11,665		38,483		294		1,100
2008		8,911		36,872		5,429		5,672		44,354		62,311		314		1,110
2009		16,640		45,964		289		1,697		7,029		61,352		111		1,490

GLJ and Sproule have assigned 59 MMboe of proven undeveloped reserves in the Engineering Reports under forecast prices and costs, together with $854 million of associated undiscounted future capital expenditures. Proven undeveloped capital spending in the first two forecast years of the Engineering Reports accounts for $570 million, or 67 percent, of the total forecast undiscounted capital expenditures for proven undeveloped reserves. These figures increase to $790 million, or 93 percent, during the first five years of the Engineering Reports. The majority of our proven undeveloped reserves evaluated in the Engineering Reports are attributable to future oil development from infill drilling and water injection enhanced oil recovery projects. For further information, see "Risk Factors".

Probable Undeveloped Reserves

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

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

Prior thereto		22,466		22,466		974		974		32,749		32,749		1,745		1,745
2007		5,290		24,160		729		1,432		10,896		25,619		257		1,836
2008		11,175		32,161		13,543		13,361		57,360		79,269		504		2,042
2009		26,110		51,166		460		2,351		7,343		60,475		83		1,857

GLJ and Sproule have assigned 65 MMboe of probable undeveloped reserves in the Engineering Reports under forecast prices and costs, together with $687 million of associated undiscounted future capital expenditures. Probable undeveloped capital spending in the first two forecast years of the Engineering Reports accounts for $223 million, or 33 percent, of the total forecast undiscounted future capital expenditures for probable undeveloped reserves. These figures increase to $591 million or 86 percent, during the first five years of the Engineering Reports. The probable undeveloped reserves evaluated in the Engineering Reports are primarily associated with proved undeveloped reserve assignments but have a less likely probability of being recovered than such associated proved undeveloped reserve assignments.

Significant Factors or Uncertainties

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

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

Additional Information Concerning Abandonment and Reclamation Costs

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

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

As of December 31, 2009, we expect to incur A&R Costs in respect of approximately 21,314 net well bores and 2,245 facilities. The total amount of A&R Costs, net of estimated salvage values, that we expect to incur, including wells that extend beyond the 50-year limit in the Engineering Reports, are summarized in the following table:

Period	Abandonment and Reclamation Costs Escalated at 2% Undiscounted (MM$)		Abandonment and Reclamation Costs Escalated at 2% Discounted at 10% (MM$)
Total liability as at December 31, 2009		2,652		326

Anticipated to be paid in 2010		55		50
Anticipated to be paid in 2011		57		47
Anticipated to be paid in 2012		59		44

The above table includes certain A&R Costs, net of salvage values, not included in the Engineering Reports and not deducted in estimating future net revenue as disclosed earlier in this Annual Information Form. Escalated at two percent and undiscounted, the A&R Costs not deducted were $1,433 million, and escalated at two percent and discounted at 10 percent, these A&R Costs were $176 million.

OTHER OIL AND GAS INFORMATION

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

Introduction

Penn West participates in the exploration for, and the development and production of, oil and natural gas principally in western Canada. Our portfolio of properties as at December 31, 2009 includes both unitized and non-unitized oil and natural gas production. In general, the properties contain long-life, low-decline rate reserves and include interests in several major oil and gas fields. The majority of our proved plus probable reserves are located in Canada in the provinces of Alberta, British Columbia, Saskatchewan and Manitoba, and in the Northwest Territories. We also have minor proved plus probable reserves interests in the United States in the States of Montana, Wyoming and North Dakota.

Major Operating Regions

Our production and reserves are attributed to more than 400 producing properties. No single property accounts for more than 10 percent of our proved plus probable reserves. Penn West's operations are managed based on five major operating regions: (i) Southern District; (ii) Central District; (iii) Eastern District; (iv) North West Alberta District; and (v) Northern District. The following table shows our reported average daily production in 2009 and proved plus probable reserves, as at December 31, 2009, by major operating region. These major operating regions represented approximately 100 percent of our average daily production in 2009 and approximately 100 percent of our total gross proved plus probable reserves (based on forecast cost and price assumptions) as assigned by GLJ and Sproule in the Engineering Reports.

	Average Daily Production in 2009						Proved Plus Probable Gross Reserves as at December 31, 2009						Land as at December 31, 2009 (thousands of acres)
	Crude Oil and NGLs (bbl/d)		Natural Gas (MMcf/d)		Total Oil Equivalent (boe/d)		Crude Oil and NGLs (MMbbl)		Natural Gas (Bcf)		Total Oil Equivalent (MMboe)		Producing		Non-producing		Total
Southern		29,617		54		38,666		163		175		192		910		752		1,662
Eastern		23,506		44		30,789		73		90		88		731		249		980
Central		29,685		183		60,085		147		560		240		1,209		253		1,462
NW Alberta		17,694		37		23,844		78		103		95		514		465		979
Northern		3,471		122		23,837		12		364		73		683		706		1,389
Total		103,973		440		177,221		472		1,292		687		4,047		2,425		6,472
	59% of daily production		41% of daily production				69% of total reserves		31% of total reserves

The following map illustrates Penn West's five major operating regions as at December 31, 2009.

The following is a description of our principal oil and natural gas properties and our related operations and activities by major operating region as at December 31, 2009. Information in respect of gross and net acres and well counts is as at December 31, 2009, and information in respect of production is for the year ended December 31, 2009, 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, 2009 may not directly correspond to the stated production for the year, which only includes production since the date the interests were acquired by us. The estimates of reserves and future net revenue for individual properties may not reflect the same confidence level as estimates of reserves and future net revenue for all properties, due to the application of statistical methods of aggregating individual properties.

Southern District

The Southern District runs within the southern boundaries of Manitoba, Saskatchewan and Alberta. This district also contains minor operations and land positions in the states of North Dakota, Wyoming and Montana. In 2009, production in this district averaged 38,666 boe/d, comprised of 29,617 bbl/d of crude oil and natural gas liquids and 54MMcf/d of natural gas.

As at December 31, 2009, Penn West had a developed and undeveloped land position of approximately 1.7 million net acres in the Southern District. In 2009, capital investment by Penn West in this district was approximately $302 million. Penn West drilled 52 new wells in the Southern District in 2009. In 2010, Penn West plans overall capital expenditures to total approximately $205 million for the Southern District.

In Southeast Saskatchewan and Southwest Manitoba, Penn West has been active on a number of fronts. In 2009, our focus was on the assessment of the Lower Amaranth pool in the Waskada area of Southwest Manitoba where Penn West drilled seven horizontal multi-stage fracture wells and continued to aggregate lands in this tight light oil play. Also in 2009, we worked on optimization opportunities in Penn West's legacy asset base in Southeast Saskatchewan and participated in the Weyburn unit operated by Cenovus Energy Inc., which is currently under CO2 flood for enhanced oil recovery. Penn West holds a 21% interest in this unit. We plan total capital expenditures of approximately $75 million for operated properties in Southeast Saskatchewan and approximately $45 million for the Weyburn unit in 2010.

In Southwest Saskatchewan, the predominant play for Penn West in 2009 was the Leitchville (Lower Shaunavon horizon) tight medium oil play. This is an unconventional "resource" play to which multi-stage horizontal fracture technology has been applied. In 2009, Penn West drilled 28 wells in the Lower Shaunavon horizon. In 2010, Penn West divested most of its interests in this area and therefore expects to drill only two wells in the Lower Shaunavon horizon in 2010 to assess our remaining lands in the play. For more information regarding the disposition of our interests in the Leitchville area, see "General Development of the Business – History and Development – 2010 Developments – Asset Exchange Agreement".

In Southern Alberta, Penn West drilled six new wells in 2009, targeting mainly the Viking and Colony zones as well as 18 re-entry wells in the mid-Mannville horizons. In 2010, Penn West plans to drill up to 60 additional wells in Southern Alberta. We plan total capital expenditures of approximately $85 million for Southern Alberta in 2010.

Eastern District

The Eastern District straddles the Saskatchewan and Alberta border and is just north of the Southern District. This district contains most of Penn West's heavy oil properties. The Eastern District is characterized by multi-zone crude oil potential. In 2009, production in this district averaged 30,789 boe/d, comprised of 23,506 bbl/d of crude oil and natural gas liquids and 44 MMcf/d of natural gas.

As at December 31, 2009, Penn West had a developed and undeveloped land position of approximately 1.0 million net acres in the Eastern District. In 2009, capital investment by Penn West in the Eastern District was approximately $64 million. We drilled 19 new wells, including two stratigraphic test wells. In 2009, Penn West divested certain heavy oil assets in the Wainright area that were producing approximately 6,000 boe per day at the time of such divestment.

In 2010, Penn West expects capital expenditures to total approximately $100 million for the Eastern District. Of such amount, we expect total capital expenditures of approximately $65 million to be targeted for the Dodsland area which is a major property for Penn West in the Eastern District in which we plan to drill approximately 40 to 50 wells in 2010.

Central District

The Central District runs from the eastern border of the Eastern District and stretches from northeast of Edmonton to just north of Calgary and runs west to the foothills of Alberta. This district is Penn West's largest district in terms of production. The district is characterized by legacy light-oil assets and gas pools with multi-zone potential. In 2009, production in this district averaged approximately 60,085 boe/d comprised of 29,685 bbl/d of crude oil and natural gas liquids and 183 MMcf/d of natural gas.

As at December 31, 2009, Penn West had a developed and undeveloped land position of approximately 1.5 million net acres in the Central District. In 2009, Penn West drilled 14 new wells in this district and made a capital investment of approximately $152 million. In 2010, Penn West expects overall capital expenditures to total approximately $125 million for the Central District.

The Cardium assets are key properties for Penn West in the Central District. In a broad geographical area in Alberta extending from Carrot Creek in the northwest through Pembina and south to Willisden Green, multi-stage horizontal fracture technology is being used with a view to increasing oil recovery from established reservoirs and to extend the productive areal extent of these fields. Penn West drilled four producing Cardium wells in the Pembina field in 2009 and plans to drill approximately 35 to 50 horizontal wells in several different areas of the Cardium trend in 2010.

Penn West initiated a CO2 flood pilot project for enhanced oil recovery in the Pembina area in early 2005 which underwent expansion in 2008. In conjunction with such pilot work to date, Penn West has been and continues to be in discussions with various parties regarding the supply of CO2 to Penn West. We are also involved in numerous commercial CO2 flood projects throughout Western Canada including the Joffre area in Alberta and the Weyburn and Midale areas in Saskatchewan.

North West Alberta District

The North West Alberta District is located north of Edmonton and is bounded by the British Columbia border to the west. This district is predominantly a light oil district. Due to the nature of the asset base, Penn West's focus in this district has been on enhanced oil recovery. In 2009, production in this district averaged approximately 23,844 boe/d, comprised of 17,694 bbl/d of crude oil and natural gas liquids and 37 MMcf/d of natural gas.

As at December 31, 2009, Penn West had a developed and undeveloped land position of approximately 1.0 million net acres in the North West Alberta District. In 2009, Penn West drilled seven new wells in this district and made a capital investment of approximately $118 million. In 2010, Penn West expects overall capital expenditures to total approximately $90 million for the North West Alberta District.

An important asset for Penn West in the North West Alberta District is the Seal area, a heavy oil play on oil sands leases located in the Peace River area of north central Alberta. In 2009, production from the Seal area averaged approximately 1,800 boe/d. In 2010, Penn West plans to resume its resource assessment by drilling eight stratigraphic test wells and eight to ten primary production horizontal wells. In 2009, Penn West received regulatory approval to conduct a single well Cyclic Steam Injection pilot project in the Seal area, but has not yet determined the expected timing of this project.

The Swan Hills properties are another important asset for Penn West in the North West Alberta District. The Swan Hills properties are light oil "legacy" assets in the Devonian reef complex of the Beaver Hill Lake formation and provide some of Penn West's longest-life reserves. In 2008, Penn West implemented a CO2 flood pilot project for enhanced oil recovery in the South Swan Hills Unit, as part of a broader strategy to evaluate an integrated CO2 flood development plan. In 2010, Penn West expects to drill ten wells in the Swan Hills area.

Penn West continued to pursue the application of horizontal multi-stage fracture technology to the Slave Point reefs in the Otter, Swan and Red Earth fields of Northwest Alberta and expects to drill six to eight wells in these regions in 2010.

In the Mitsue area of Northwest Alberta, Penn West is assessing the potential of infill development drilling and plans to drill between five and ten wells in this area in 2010.

Northern District

The Northern District includes northeastern British Columbia, the northwestern corners of Alberta (including the Peace River Arch) and southwestern Northwest Territories. This district is characterized primarily by natural gas with multi-zone production. In 2009, this district averaged approximately 23,837 boe/d comprised of 3,471 bbl/d of crude oil and natural gas liquids and 122 MMcf/d of natural gas.

As at December 31, 2009, Penn West had a developed and undeveloped land position of approximately 1.4 million net acres in the Northern District. In 2009, due in part to low natural gas prices, Penn West drilled only two new wells and made a capital investment of approximately $52 million. In 2010, Penn West expects to drill between eight and ten wells in the district with overall capital expenditures to total approximately $35 million for the Northern District.

An important asset for Penn West, located in the most northern portion of the Northern District, is the Wildboy area, a legacy grassroots Penn West exploration and development property with all weather access roads, which targets natural gas production. The Wildboy area is served by a natural gas plant and sales pipeline that is 100 percent owned and operated by Penn West and connects to the TransCanada pipeline system in Alberta.

In the immediate area of its Wildboy field and gas plant, Penn West is testing and evaluating the economic potential of a shale gas play in the Cordova Embayment, located just east of the Horn River development. In 2009, Penn West completed and tested a well to collect data on this play. In 2010, Penn West expects to continue evaluation of the play with two wells expected to be drilled and planned capital expenditures of approximately $7 million to $10 million.

Another important property for Penn West in the Northern District is our position in the Montney natural gas play located near Dawson Creek, British Columbia. In 2010, Penn West plans to drill five to seven horizontal wells and expects total capital expenditures of approximately $25 million for the Montney play.

Additional Information

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

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

Oil And Gas Wells

The following table sets forth the number and status of wells in which we had a working interest as at December 31, 2009.

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

Alberta		9,862		5,485		9,560		3,950		6,523		3,514		25,945		12,949
British Columbia		145		50		979		468		418		145		1,542		663
Saskatchewan		7,670		4,960		1,224		683		3,078		1,452		11,972		7,095
Manitoba		715		339		1		-		217		105		933		444
Northwest Territories		3		-		7		1		37		7		47		8
Wyoming		-		-		301		124		68		23		369		147
Montana		5		2		-		-		-		-		5		2
North Dakota		16		6		1		-		-		-		17		6
Total		18,416		10,842		12,073		5,226		10,341		5,246		40,830		21,314

Properties with no Attributed Reserves

The following table sets out the unproved properties in which we have an interest as at December 31, 2009.

	Unproved Properties (thousands of acres)
	Gross		Net

Alberta		1,431		1,120
British Columbia		697		524
Saskatchewan		635		530
Manitoba		206		201
Northwest Territories		92		18
Wyoming		16		8
Montana		3		2
North Dakota		26		22
Total		3,106		2,425

We currently have no material work commitments on these lands. The primary lease or extension term on approximately 264,000 net acres of unproved property will expire by December 31, 2010. The right to explore, develop and exploit these leases will be surrendered unless we qualify them for continuation based on existing production, drilling or technical mapping.

Tax Horizon

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

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

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

Capital Expenditures

The following table summarizes capital expenditures related to our activities for the year ended December 31, 2009, irrespective of whether such costs were capitalized or charged to expense when incurred.

	2009 MM$

Property Acquisitions (Dispositions)
Proved Properties		(369	)
Unproved Properties		19
Exploration Costs(1)		79
Development Costs(2)		546
Corporate Costs		44
Total Capital Expenditures		319
Corporate Acquisitions		116
Total Expenditures		435

Notes:

(1)	Includes costs of land acquired, geological and geophysical capital expenditures and drilling costs for 2009 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, 2009.

	Exploratory Wells				Development Wells
	Gross		Net		Gross		Net
Oil		6		5		96		63
Natural Gas		10		7		30		10
Service		1		1		10		6
Dry		-		-		2		2
Total		17		13		138		81

We currently estimate that our capital expenditures in 2010 will be between $700 million and $850 million in order to execute our current 2010 capital programs. The primary components of our programs are described under the heading "Other Oil and Gas information – Description of Our Properties, Operations and Activities in Our Major Operating Regions".

Production Estimates

The following table sets out the volume of our production estimated for the year ended December 31, 2010 which is reflected in the estimates of gross proved reserves and gross probable reserves disclosed in the tables contained under "Disclosure of Reserves Data" above.

	Light and Medium Oil				Heavy Oil				Natural Gas				Natural Gas Liquids				Total Oil Equivalent
	(bbl/d)				(bbl/d)				(Mcf/d)				(bbl/d)				(boe/d)
	Gross		Net		Gross		Net		Gross		Net		Gross		Net		Gross		Net
Proved Developed Producing		60,841		51,286		17,925		15,472		357,969		301,029		9,185		6,589		147,613		123,519
Proved Developed Non-Producing		994		865		322		272		12,945		10,389		216		166		3,689		3,035
Proved Undeveloped		3,656		3,603		546		514		3,105		2,759		458		437		5,177		5,014
Total Proved		65,491		55,754		18,792		16,258		374,019		314,177		9,860		7,193		156,480		131,567
Total Probable		3,309		2,741		647		503		24,981		19,379		544		400		8,664		6,873
Total Proved Plus Probable		68,800		58,495		19,439		16,761		399,000		333,556		10,404		7,592		165,143		138,440

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

Production History

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

	Quarter Ended 2009												Year Ended
	March 31			June 30			September 30			December 31			December 31, 2009
Average Daily Production(1)
Light and Medium Crude Oil (bbl/d)		67,864			68,148			67,666			67,371			67,760
Heavy Oil (bbl/d)		26,328			26,456			27,070			24,009			25,962
Gas (MMcf/d)		447			459			441			411			440
NGLs (bbl/d)		11,452			9,466			9,847			10,256			10,251
Combined (boe/d)		180,096			180,601			178,124			170,164			177,221

Average Net Production Prices Received
Light and Medium Crude Oil ($/bbl)		45.98			60.85			67.41			72.66			61.79
Heavy Oil ($/bbl)		36.92			56.71			58.72			62.97			53.75
Gas ($/Mcf)		5.37			3.68			3.13			4.39			4.13
NGLs ($/bbl)		35.73			38.37			41.74			48.71			41.07
Combined ($/boe)		38.30			42.62			44.58			51.19			44.11

Royalties Paid
Light and Medium Crude Oil ($/bbl)		6.87			10.10			11.38			13.71			10.53
Heavy Oil ($/bbl)		3.88			7.17			8.55			9.52			7.26
Gas ($/Mcf)		1.22			0.63			0.45			0.69			0.75
NGLs ($/bbl)		9.67			13.09			12.08			15.06			12.40
Combined ($/boe)		6.80			7.14			7.41			9.35			7.66

Production Costs(2)(3)
Light and Medium Crude Oil ($/bbl)		20.51			20.71			20.55			20.34			20.53
Heavy Oil ($/bbl)		15.79			15.62			15.37			15.37			15.54
Gas ($/Mcf)		1.56			1.51			1.56			1.63			1.57
NGLs ($/bbl)		15.87			16.12			15.98			15.80			15.94
Combined ($/boe)		14.93			14.79			14.90			15.10			14.93

Transportation
Light and Medium Crude Oil ($/bbl)		-			-			-			-			-
Heavy Oil ($/bbl)		0.05			0.06			0.06			0.07			0.06
Gas ($/Mcf)		0.21			0.20			0.21			0.21			0.21
NGLs ($/bbl)		-			-			-			-			-
Combined ($/boe)		0.54			0.51			0.53			0.52			0.52

(Gain)/Loss on Risk Management Contracts
Light and Medium Crude Oil ($/bbl)		(20.47	)		(10.01	)		(5.62	)		(1.78	)		(9.43	)
Heavy Oil ($/bbl)		-			-			-			-			-
Gas ($/Mcf)		(0.77	)		(0.66	)		(0.82	)		(0.49	)		(0.69	)
NGLs ($/bbl)		-			-			-			-			-
Combined ($/boe)		(9.63	)		(5.46	)		(4.17	)		(1.89	)		(5.32	)

Netback Received(4)
Light and Medium Crude Oil ($/bbl)		39.07			40.05			41.10			40.38			40.16
Heavy Oil ($/bbl)		17.20			33.86			34.74			38.01			30.89
Gas ($/Mcf)		3.15			2.00			1.73			2.35			2.29
NGLs ($/bbl)		10.18			9.16			13.69			17.86			12.73
Combined ($/boe)		25.66			25.64			25.91			28.11			26.32

Notes:

(1)	Before deduction of royalties.

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

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

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

Marketing Arrangements

Our marketing approach incorporates the following primary objectives:

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

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

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

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

Natural Gas Marketing

In 2009, we received an average price from the sale of natural gas, before adjustments for hedging activities, of $4.13/Mcf compared to $8.43/Mcf realized in 2008. Approximately 90 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 approximately two percent of sales.

Oil and Liquids Marketing

In terms of our entire liquids production, approximately 65 percent is light and medium oil, 25 percent is conventional heavy oil and 10 percent is NGLs. In regard specifically to crude oil, our average quality is 31 degrees API, which is comprised of an average quality for our light and medium oil of 35 degrees API and an average quality for our conventional heavy oil of 16 degrees API.

To reduce risk, we market the majority of our production to large credit-worthy counter-parties or end-users on varying term contracts and actively manage our heavy oil supply by finding opportunities to optimize netbacks through blending, trucking and proprietary handling of emulsion. Blending costs are also controlled through the use of proprietary condensate supply.

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

	2009				2008
	Light and Medium Oil and NGLs		Heavy Oil		Light and Medium Oil and NGLs		Heavy Oil
Quarter ended	($/bbl)		($/bbl)		($/bbl)		($/bbl)

March 31		44.50		36.92		88.77		66.64
June 30		58.11		56.71		111.88		93.12
September 30		64.15		58.72		110.45		98.07
December 31		69.49		62.97		53.72		38.67

Forward Contracts

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

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

As at December 31, 2009, we were not bound by any agreement (including a transportation agreement), directly or through an aggregator, under which we may be precluded from fully realizing, or may be protected from the full effect of, future market prices for oil or natural gas, except for agreements disclosed by us as financial instruments in accordance with Section 3861 of the CICA Handbook, or as contractual obligations or commitments in accordance with Section 3280 of the CICA Handbook. For information regarding our outstanding financial instruments as at December 31, 2009, see Note 8 (Risk management) to our consolidated financial statements as at and for the year ended December 31, 2009, which have been filed on SEDAR at www.sedar.com.

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

APPENDIX B

MANDATE OF THE AUDIT COMMITTEE

PURPOSE

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", and together with the Company, "Penn West"), 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 qualifications and independence of the Trust's independent auditors, and the performance of the Trust's internal audit function, if any.

The objectives of the Committee are as follows:

(a)	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;

(b)	To provide better communication between directors and independent auditors;

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

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

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

(f)	To assist the Board in meeting its responsibilities regarding the oversight of the performance of Penn West's independent auditors and internal audit function (if any); and

(g)	To assist the Board in meeting its responsibilities regarding the oversight of Penn West's compliance with legal and regulatory requirements.

2.	SPECIFIC DUTIES AND RESPONSIBILITIES

Subject to the powers and duties of the Board, the Committee will perform the following duties:

(a)	Satisfy itself on behalf of the Board that Penn West's internal control systems are sufficient to reasonably ensure that:

(i)

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

(ii)

internal controls over financial reporting are sufficient to meet the requirements under National Instrument 52-109 Certification of Disclosure in Issuers' Annual and Interim Filings and the United States Securities Exchange Act of 1934, as amended, and

(iii)

there is compliance with legal, ethical and regulatory requirements.

(b)	Review the annual and interim 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:

(i)

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

(ii)

review of significant accruals, reserves or other estimates such as the ceiling test calculation;

(iii)

review of accounting treatment of unusual or non-recurring transactions;

(iv)

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

(v)

review of compliance with covenants under loan agreements and Trust Indenture pursuant to which the Trust was formed and is governed;

(vi)

review of adequacy of the asset retirement obligations;

(vii)

review of disclosure requirements for commitments and contingencies;

(viii)

review of adjustments raised by the independent auditors, whether or not included in the financial statements;

(ix)

review of unresolved differences between management and the independent auditors, if any;

(x)

review of reasonable explanations of significant variances with comparative reporting periods; and

(xi)

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

(c)	Review, discuss and recommend for approval by the Board the annual and interim financial statements and related information included in prospectuses, management discussion and analysis, information circular-proxy statements and annual information forms, prior to recommending board approval.

(d)

Discuss the Trust's interim 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).

(e)	With respect to the appointment of independent auditors by the Board, the Committee shall:

(i)

on an annual basis, review and discuss with the auditors all relationships the auditors have with the Trust and the Company to determine the auditors’ independence, 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;

(ii)

be directly responsible for 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;

(iii)

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

(iv)

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;

(v)

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;

(vi)

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

(vii)

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.

(f)

The Committee may delegate to one or more members of the Committee authority to pre-approve non-audit services in satisfaction of 2(e) (vii) above 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:

(i)

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

(ii)

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

(iii)

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

provided that in order for the pre-approval requirements to be satisfied for any non-audit services that are not pre-approved in accordance with the procedures set forth above:

(iv)

the aggregate amount of all non-audit services that were not pre-approved (if any) must be 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;

(v)

the Trust or the subsidiary entity, as the case may be, must not have recognized the services as non-audit services at the time of the engagement; and

(vi)

the services must have been 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.

(g)

At least annually, obtain and review 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.

(h)

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 the Trust and its subsidiaries.

(i)

At least annually, obtain and review 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.

(j)	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.

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

(l)	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).

(m)	Review all pending litigation to ensure disclosures are sufficient and appropriate.

(n)	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.

(o)	Review and discuss major financial risk exposures and the steps management has taken to monitor and control such exposures.

(p)	Establish procedures independent of management for:

(i)

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

(ii)

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

(q)	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.

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

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

(t)

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

(u)	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.

(v)	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.

(w)

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.

(x)	Review and discuss the effect of regulatory and accounting initiatives, as well as off-balance sheet structures, on the Trust’s financial statements.

(y)	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.

(z)	annually review the Committee's Mandate and the Committee Chair’s Terms of Reference and recommend any proposed changes to the Board for consideration; and

(aa)	review and approve any other matters specifically delegated to the Committee by the Board.

3.	KNOWLEDGE & EDUCATION

Committee members shall be "financially literate" within the meaning of NI 52-110, and should have or obtain sufficient knowledge of Penn West's financial and audit policies and procedures to assist in providing advice and counsel on related matters. Members shall be encouraged as appropriate to attend relevant educational opportunities at the expense of Penn West.

4.	COMPOSITION

(a)	The Committee shall be composed of at least three members of the Board or such greater number as the Board may from time to time determine.

(b)	Committee members shall be appointed and removed by the Board.

(c)	Each member of the Committee shall be an "independent" director in accordance with the definition of "independent" in (a) National Instrument 52-110 Audit Committees ("NI 52-110") and (b) Section 303A.02 and 303A.07(b) of the Corporate Governance Rules of the New York Stock Exchange.

(d)

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.

(e)

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 committees of more than three public companies. To the extent that any proposed nominee for membership on the Committee serves on the audit committees 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 proxy information circular and annual report on Form 40-F filed with the United States Securities and Exchange Commission.

MEETINGS

(a)

The Committee shall meet at least four times per year at the call of the Committee Chair. The Committee Chair may call additional meetings as required. In addition, a meeting may be called by the Chairman of the Board, the Chief Executive Officer, the Executive Vice President & Chief Financial Officer, the President & Chief Operating Officer or any member of the Committee.

(b)

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 shall meet with the independent auditors and management quarterly to review the Trust’s interim financials. The Committee shall also meet with management and independent auditors on an annual basis to review and discuss the Trust's annual financial statements and the management's discussion and analysis of financial conditions and results of operations.

(c)

Notice of the time and place of every meeting may be given orally, in writing, by facsimile or by other electronic means of communication to each member of the Committee at least 48 hours prior to the time fixed for such meeting. A member may, in any manner, waive notice of the meeting. Attendance of a member at a meeting shall constitute waiver of notice.

(d)	A quorum shall be a majority of the members of the Committee.

(e)	Committee meetings may be held in person, by video conference, by teleconference or by combination of any of the foregoing.

(f)	As part of each Committee meeting the Committee members will also meet "in-camera" without any members of management present.

(g)	The Committee Chair shall be a full voting member of the Committee.

(h)

If the Committee Chair is unavailable or unable to attend a meeting of the Committee, the Committee Chair shall ask another member to chair the meeting, failing which a member of the Committee present at the meeting shall be chosen to preside over the meeting by a majority of the members of the Committee present at such meeting.

(i)	The Chair of any Committee meeting (including, without limitation, any Chair selected in accordance with paragraph (g) above)) shall have a casting vote in the event of a tie on any matter upon which the Committee votes during such meeting.

(j)	The Committee shall have the right to determine who shall and who shall not be present at any time during a meeting of the Committee. However, independent directors, including the Chairman of the Board, shall always have the right to be present.

(k)	Agendas, with input from management and the Committee Chair, shall be circulated by the Committee Secretary to Committee members and relevant members of management along with appropriate meeting materials and background reading on a timely basis prior to Committee meetings.

MINUTES

(a)	The secretary to the Committee (the "Committee Secretary") will be either the Corporate Secretary of the Company or his/her delegate. The Committee Secretary shall record and maintain minutes of the meetings of the Committee.

(b)	Minutes of Committee meetings shall be approved by the Committee and maintained with Penn West's records by the Committee Secretary or designate.

7.	REPORTING / AUTHORITY

(a)

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.

(b)	Supporting schedules and information reviewed by the Committee shall be available for examination by any member of the Board.

(c)	The Committee shall have the authority to investigate any financial activity of the Trust and to communicate directly with the internal auditors (if any) and independent auditors. All employees are to cooperate as requested by the Committee.

(d)	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.

(e)	The Committee may delegate any of its duties and responsibilities hereunder to the Committee Chair or any group of members of the Committee.

(f)

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.

8.	ACCOUNTABILITY

The Committee's performance shall be evaluated by the Board as part of the Board assessment process established by the Governance Committee and the Board.

RESOURCES

(a)

The Committee may retain special legal, accounting, financial or other consultants or advisors to advise the Committee at Penn West's expense and shall have sole authority to retain and terminate any such consultants or advisors and to approve any such consultant's or advisor's fees and retention terms, subject to review by the Board.

(b)	The Committee shall have access to Penn West's senior management and documents as required to fulfill its responsibilities and shall be provided with the resources necessary to carry out its responsibilities.

(c)	The Chief Executive Officer and the Chief Financial Officer, or their designates, shall be available to attend meetings of the Committee.

(d)	Such other staff as appropriate to provide information to the Committee shall attend meetings upon invitation by the Committee, the Chief Executive Officer or the Chief Financial Officer.

(e)	The Committee may, by specific invitation, have other resource persons in attendance to assist in the discussion and consideration of matters relating to the Committee.

10.	DELEGATION

The Committee may delegate from to time to any person or committee of persons any of the Audit Committee's responsibilities that are permitted to be delegated to such person or committee in accordance with applicable laws, regulations and stock exchange requirements.

11.	STANDARDS OF LIABILITY

(a)

Nothing contained in this Mandate is intended to expand applicable standards of liability under statutory, regulatory or other legal requirements for the Board or members of the Committee. The purposes and responsibilities outlined in this Mandate are meant to serve as guidelines rather than inflexible rules and the Committee may adopt such additional procedures and standards as it deems necessary from time to time to fulfill its responsibilities, subject to applicable statutory, regulatory and other legal requirements.

(b)	The duties and responsibilities of a member of the Committee are in addition to those duties set out for a member of the Board.

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

To Convert From	To	Multiply By

Mcf	cubic metres	28.174
cubic metres	cubic feet	35.494
bbl	cubic metres	0.159
cubic metres	bbl	6.293
feet	metres	0.305
metres	feet	3.281
miles	kilometres	1.609
kilometres	miles	0.621
acres	hectares	0.405
hectares	acres	2.500
gigajoules (at standard)	MMbtu	0.948
MMbtu (at standard)	gigajoules	1.055
gigajoules (at standard)	Mcf	1.055

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

	Page

GLOSSARY OF TERMS	2
CONVENTIONS	5
ABBREVIATIONS	5
CONVERSIONS	7
SPECIAL NOTE REGARDING FORWARD-LOOKING STATEMENTS	8
NON-GAAP MEASURES	9
EFFECTIVE DATE OF INFORMATION	9
PENN WEST ENERGY TRUST	10
GENERAL DEVELOPMENT OF THE BUSINESS	12
DESCRIPTION OF OUR BUSINESS	18
CAPITALIZATION OF PWPL	19
INFORMATION RELATING TO PENN WEST	20
CORPORATE GOVERNANCE	28
AUDIT COMMITTEE DISCLOSURES	33
DISTRIBUTIONS TO UNITHOLDERS	35
MARKET FOR SECURITIES	36
INDUSTRY CONDITIONS	38
RISK FACTORS	50
MATERIAL CONTRACTS	68
LEGAL PROCEEDINGS AND REGULATORY ACTIONS	69
TRANSFER AGENTS AND REGISTRARS	69
INTEREST OF MANAGEMENT AND OTHERS IN MATERIAL TRANSACTIONS	70
INTERESTS OF EXPERTS	70
ADDITIONAL INFORMATION	70

Oil and Natural Gas Liquids		Natural Gas

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