Exhibit
99.1












PENN
WEST ENERGY TRUST





Annual
Information Form


for
the year ended December 31, 2009








March
18, 2010











TABLE
OF CONTENTS




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








APPENDIX
"A" – RESERVES DISCLOSURE





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


Appendix
A-2 – Report on Reserves Data


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





APPENDIX
"B" – MANDATE OF THE AUDIT COMMITTEE











GLOSSARY
OF TERMS





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





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





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





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





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





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





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





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





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





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





"2009 Senior Notes" has the
meaning ascribed thereto under "General Development of the Business – History
and Development – Year Ended December 31, 2009 – Private Placement of 2009
Senior Notes".





"2010 Senior Notes" has the
meaning ascribed thereto under "General Development of the Business – History
and Development – 2010 Developments – Private Placement of 2010 Senior
Notes".





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





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





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





"Canadian GAAP" means Canadian
generally accepted accounting principles.





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





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





"CBM" means coalbed
methane.





2





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





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





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





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





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





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





"Form 40-F" means our Annual
Report on Form 40-F for the fiscal year ended December 31, 2009, filed with the
SEC.





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





"GLJ Report" means the report
prepared by GLJ dated February 11, 2010 evaluating approximately 48 percent of
the crude oil, natural gas and natural gas liquids reserves of Penn West and the
net present value of future net revenue attributable to those reserves effective
as at December 31, 2009.





"Gross" means:





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





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





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





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





"Net" means:





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





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





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





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





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





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





3





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





"NYSE" means the New York Stock
Exchange.





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





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





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





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





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





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





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





"Reece" means Reece Energy
Exploration Corp., a corporation incorporated under the laws of the Province of
Alberta.





"Reece Acquisition" means the
plan of arrangement under the ABCA pursuant to which Penn West acquired Reece on
April 30, 2009.





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





"SIFT" has the meaning ascribed
thereto under "General Development of the Business – History and Development –
Year Ended December 31, 2006 – Changes to Taxation of Income
Trusts".





"SIFT Tax" has the meaning
ascribed thereto under "General Development of the Business – History and
Development – Year Ended December 31, 2006 – Changes to Taxation of Income
Trusts".





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





"Sproule Report" means the
report prepared by Sproule dated February 24, 2010 evaluating approximately 37
percent and auditing approximately 15 percent of the crude oil, natural gas and
natural gas liquids reserves of Penn West and the net present value of future
net revenue attributable to those reserves effective as at December 31,
2009.





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





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





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





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





4





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





"TSX" means the Toronto Stock
Exchange.





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





"Unitholders" means holders of
Trust Units.





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





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





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





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





CONVENTIONS





Certain
terms used herein are defined in the "Glossary of Terms".  Certain
other terms used herein but not defined herein are defined in NI 51-101 and,
unless the context otherwise requires, shall have the same meanings herein as in
NI 51-101.  A reconciliation of the principal differences between Penn
West's financial results calculated under Canadian GAAP and under U.S. GAAP is
included in the Form 40-F.  On March 18, 2010, the exchange rate for
U.S. dollars, expressed in Canadian dollars, based on the noon rate as reported
by the Bank of Canada, was Cdn$1.00 equals US$0.9863.





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





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





ABBREVIATIONS








Oil and Natural Gas Liquids
            Natural Gasbbl
            barrel
      or barrels
            GJ
            gigajoulebbl/d
            barrels
      per day
            GJ/d
            gigajoules
      per dayMbbl
            thousand
      barrels
            Mcf
            thousand
      cubic feetMMbbl
            million
      barrels
            MMcf
            million
      cubic feetNGLs
            natural
      gas liquids
            Bcf
            billion
      cubic feetMMboe
            million
      barrels of oil equivalent
            Mcf/d
            thousand
      cubic feet per dayMboe
            thousand
      barrels of oil equivalent
            MMcf/d
            million
      cubic feet per dayboe/d
            barrels
      of oil equivalent per day
            m3
            cubic
      metres





5




OtherBOE
      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.








OIL
AND GAS INFORMATION ADVISORIES





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





All
production and reserves quantities included in this Annual Information Form
(including the Appendices hereto) have been prepared in accordance with Canadian
practices and specifically in accordance with NI 51-101.  These
practices are different from the practices used to report production and to
estimate reserves in reports and other materials filed with the SEC by companies
in the United States  Nevertheless, as part of Penn West’s Annual
Report on Form 40-F for the year ended December 31, 2009 filed with the SEC,
Penn West has disclosed proved reserves quantities using the standards contained
in SEC Regulation S-X, and the standardized measure of discounted future net
cash flows relating to proved oil and gas reserves determined in accordance with
the U.S. Financial Accounting Standards Board, "Disclosures About Oil and Gas
Producing Activities", which disclosure complies with the SEC's rules for
disclosing oil and gas reserves.





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





6





CONVERSIONS





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




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





7





SPECIAL
NOTE REGARDING FORWARD-LOOKING STATEMENTS





In the
interest of providing Unitholders and potential investors with information
regarding Penn West, including management's assessment of Penn West's future
plans and operations, certain statements contained and incorporated by reference
in this document constitute forward-looking statements or information
(collectively "forward-looking
statements") within the meaning of the "safe harbour" provisions of
applicable securities legislation.  Forward-looking statements are
typically identified by words such as "anticipate", "continue", "estimate",
"expect", "forecast", "may", "will", "project", "could", "plan", "intend",
"should", "believe", "outlook", "potential", "target" and similar words
suggesting future events or future performance.  In addition,
statements relating to "reserves" or "resources" are deemed to be
forward-looking statements as they involve the implied assessment, based on
certain estimates and assumptions, that the reserves and resources described
exist in the quantities predicted or estimated and can be profitably produced in
the future.  In particular, this document and the documents
incorporated by reference herein contain, without limitation, forward-looking
statements pertaining to the following: the performance characteristics of our
oil and natural gas properties; the potential impact on our business, business
strategies and plans, business model, future growth prospects, distribution
policies and Unitholders of the SIFT Tax and the different actions that we might
take in response to the SIFT Tax and the potential impact those actions could
have on us and our Unitholders, including without limitation, our intention to
convert to a dividend paying corporation prior to mid-2011, our potential
ability to shield our taxable income from income tax using our tax pools for a
period of time following the implementation of the SIFT Tax, and the impact this
would have on our distributions and Unitholders; the impact that government
royalty frameworks may have on us, including on our business strategies and
plans; our environmental regulation compliance costs and strategies, the
sufficiency of our environmental program and our ability to fund our asset
retirement obligations; oil and natural gas production level estimates; our 2010
capital expenditure levels, the timing of making said expenditures, the key
elements of our 2010 capital expenditure program and the method of funding said
expenditures; our business strategies; our exploration and development plans for
our oil and natural gas properties in 2010 and beyond; funding sources for
distributions and distribution levels; the quantity and recoverability of our
oil and natural gas reserves and resources; currency exchange rates, inflation
rates and interest rates; the nature and effectiveness of our risk management
strategies; our outlook for oil and natural gas prices; and our intention and
ability to maintain a balanced portfolio of liquids and natural gas production
and the benefits we may derive therefrom.





With
respect to forward-looking statements contained or incorporated by
referencein this
document, we have made assumptions regarding, among other things: our intention
to convert from a trust structure to a corporate or other structure, including
the timing thereof and the method of accomplishing such conversion; the laws and
regulations that we will be required to comply with, including laws and
regulations relating to taxation, royalty regimes and environmental protection;
future capital expenditure levels; future oil and natural gas prices and
differentials between light, medium and heavy oil prices; future oil and natural
gas production levels; future exchange rates and interest rates; the amount of
future cash distributions that we intend to pay; the cost of expanding our
property holdings; our ability to obtain equipment in a timely manner to carry
out development activities; our ability to market our oil and natural gas
successfully to current and new customers; the impact of increasing competition;
our ability to obtain financing on acceptable terms; and our ability to add
production and reserves through our development and exploitation
activities.  In addition, many of the forward-looking statements
contained in this document are located proximate to assumptions that are
specific to those forward-looking statements, and such assumptions should be
taken into account when reading such forward-looking statements.





Although
Penn West believes that the expectations reflected in the forward-looking
statements contained or incorporated by reference in this document, and the
assumptions on which such forward-looking statements are made, are reasonable,
there can be no assurance that such expectations will prove to be
correct.  Readers are cautioned not to place undue reliance on
forward-looking statements included or incorporated by reference in this
document, as there can be no assurance that the plans, intentions or
expectations upon which the forward-looking statements are based will
occur.  By their nature, forward-looking statements involve numerous
assumptions, known and unknown risks and uncertainties that contribute to the
possibility that the predictions, forecasts, projections and other
forward-looking statements will not occur, which may cause Penn West's actual
performance and financial results in future periods to differ materially from
any estimates or projections of future performance or results expressed or
implied by such forward-looking statements.  These risks and
uncertainties include, among other things: the impact of weather conditions on
seasonal demand and our ability to execute capital programs; risks inherent in
oil and natural gas operations; uncertainties associated with estimating
reserves and resources; competition for, among other things, capital,
acquisitions of reserves, resources, undeveloped lands and skilled personnel;
incorrect assessments of the value of acquisitions; geological, technical,
drilling and processing problems; general economic conditions in Canada, the
U.S. and globally, and in particular, the effect that those conditions have on
commodity prices and our access to capital; industry conditions, including
fluctuations in the price of oil and natural gas; royalties payable in respect
of our oil and natural gas production and changes thereto; changes in government
regulation of the oil and natural gas industry, including environmental
regulation; fluctuations in foreign exchange or interest rates; unanticipated
operating events that can reduce production or cause production to be shut-in or
delayed; failure to obtain industry partner and other third-party consents and
approvals when required; stock market volatility and market valuations; OPEC's
ability to control production and balance global supply and demand of crude oil
at desired price levels; political uncertainty, including the risks of
hostilities, in the petroleum producing regions of the world; the need to obtain
required approvals from regulatory authorities from time to time; failure to
realize the anticipated benefits of acquisitions, including the completed
acquisitions discussed herein; changes in taxation laws and regulations that
affect us and our securityholders; changes in government royalty frameworks in
jurisdiction in which we operate and the impact that such changes may have on
us; uncertainty of obtaining required approvals in respect of acquisitions and
mergers; and the other factors described under "Risk Factors" in this document
and in Penn West's public filings available in Canada at www.sedar.com and in
the United States at www.sec.gov.  Readers are cautioned that this
list of risk factors should not be construed as exhaustive.





8





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





NON-GAAP
MEASURES





This
Annual Information Form includes measures not defined under generally accepted
accounting principles ("GAAP"), including funds flow
and netbacks.Non-GAAP measures
do not have any standardized meaning prescribed by GAAP and are therefore
unlikely to be comparable to similar measures presented by other
issuers.  Funds flow is cash flow from operating activities before
changes in non-cash working capital and asset retirement
expenditures.  Funds flow is used to assess our ability to fund
distributions and planned capital programs.  Netback is a
per-unit-of-production measure of operating margin used in capital allocation
decisions.  For more information, see Penn West's management's
discussion and analysis for the year ended December 31, 2009 (available on SEDAR
at www.sedar.com and on EDGAR at www.sec.gov), which includes a reconciliation
of "funds flow" to cash flow from operating activities and sets out the method
that we use to calculate our netbacks.





EFFECTIVE
DATE OF INFORMATION





Except
where otherwise indicated, the information in this Annual Information Form is
presented as at the end of Penn West's most recently completed financial year,
being December 31, 2009.





9





PENN
WEST ENERGY TRUST





General





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





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





Inter-Corporate
Relationships





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





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





Our
Organizational Structure





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





10









Notes:





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





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





(3)
            PWPL
      was formed effective as of January 1, 2010 pursuant to the amalgamation of
      Penn West Petroleum Ltd., Reece Energy Exploration Corporation and
      Lodgepole Energy Management
Corporation.





(4)
            As
      at the date hereof, PWPL, Trocana Resources Inc. andCanetic
      Saskatchewan Trustare the partners
      of Penn West Partnership.





(5)
            The
      other Operating Entities are direct or indirect wholly-owned subsidiaries
      of Penn West.  As at December 31, 2009, other than PWPL and the
      Penn West Partnership, Penn West does not have any subsidiaries: (i) the
      total assets of which exceed 10 percent of Penn West's consolidated assets
      (or 20 percent of Penn West's consolidated assets when aggregated with all
      other subsidiaries of Penn West other than PWPL and the Penn West
      Partnership); or (ii) the sales and operating revenues of which exceed 10
      percent of Penn West's consolidated sales and operating revenues (or 20
      percent of Penn West's consolidated sales and operating revenues when
      aggregated with all other subsidiaries of Penn West other than PWPL and
      the Penn West Partnership).





11




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.
  12
  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 $14billion (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).
  13
  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.
  14
  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 $50million 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.
  15
  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
torepay 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.
  16
  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.
  17
  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 1,950employees.
 
 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 fromsix 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.
  18
  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.
  19
  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.
  20
  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.
  21
  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.
  22
  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 662⁄3 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.
  23
  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 662⁄3 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 662⁄3 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.
  24
  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.
  25
  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 thehighest 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.
  26
  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.
  27
  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.
  28
  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
      YearsJames
      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).
  29
  Name, Province/State and Country of
      Residence
              
              Positions and Offices
      Held
              
              Principal Occupations during the Five Preceding
      YearsJohn
      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.
  30
  Name, Province/State and Country of
      Residence
              
              Positions and Offices
      Held
              
              Principal Occupations during the Five Preceding
      YearsHilary
      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.
  31
  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
  32
  (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.
  33
  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.
  34
  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:
  35
  Month
              
              2010
                  ($)
              
              
              2009
                  ($)
              
              
              2008
                  ($)
              
              
              2007
                  ($)January
              
              
              0.15
              
              
              
              0.23
              
              
              
              0.34
              
              
              
              0.34February
              
              
              0.15
              
              
              
              0.23
              
              
              
              0.34
              
              
              
              0.34March
              
              
              0.15
              
              
              
              0.23
              
              
              
              0.34
              
              
              
              0.34April
              
              
              -
              
              
              
              0.15
              
              
              
              0.34
              
              
              
              0.34May
              
              
              -
              
              
              
              0.15
              
              
              
              0.34
              
              
              
              0.34June
              
              
              -
              
              
              
              0.15
              
              
              
              0.34
              
              
              
              0.34July
              
              
              -
              
              
              
              0.15
              
              
              
              0.34
              
              
              
              0.34August
              
              
              -
              
              
              
              0.15
              
              
              
              0.34
              
              
              
              0.34September
              
              
              -
              
              
              
              0.15
              
              
              
              0.34
              
              
              
              0.34October
              
              
              -
              
              
              
              0.15
              
              
              
              0.34
              
              
              
              0.34November
              
              
              -
              
              
              
              0.15
              
              
              
              0.34
              
              
              
              0.34December
              
              
              -
              
              
              
              0.15
              
              
              
              0.34
              
              
              
              0.34Total
              
              
              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.
 
 TSXUnit price ($)
              
              
              Unit price ($)Period
              
              High
              
              
              Low
              
              
              VolumeJanuary
              
              
              16.18
              
              
              
              13.55
              
              
              
              28,122,634February
              
              
              14.08
              
              
              
              10.94
              
              
              
              28,127,890March
              
              
              14.19
              
              
              
              8.82
              
              
              
              43,761,160April
              
              
              13.85
              
              
              
              11.51
              
              
              
              31,291,751May
              
              
              15.48
              
              
              
              13.08
              
              
              
              27,209,018June
              
              
              15.92
              
              
              
              13.67
              
              
              
              23,775,522July
              
              
              14.89
              
              
              
              12.51
              
              
              
              18,345,957August
              
              
              14.87
              
              
              
              13.75
              
              
              
              16,938,434September
              
              
              16.98
              
              
              
              13.60
              
              
              
              27,357,009October
              
              
              19.15
              
              
              
              15.30
              
              
              
              28,132,716November
              
              
              19.49
              
              
              
              17.50
              
              
              
              20,623,334December
              
              
              18.95
              
              
              
              17.36
              
              
              
              12,868,963
 
 
 NYSEUnit price (US$)
              
              
              Unit price (US$)Period
              
              High
              
              
              Low
              
              
              VolumeJanuary
              
              
              13.72
              
              
              
              11.06
              
              
              
              74,868,480February
              
              
              11.57
              
              
              
              8.66
              
              
              
              72,387,176March
              
              
              11.54
              
              
              
              6.77
              
              
              
              97,564,920April
              
              
              11.45
              
              
              
              9.07
              
              
              
              58,198,880May
              
              
              14.19
              
              
              
              10.99
              
              
              
              67,340,968June
              
              
              14.68
              
              
              
              11.83
              
              
              
              58,821,888July
              
              
              13.78
              
              
              
              10.70
              
              
              
              47,887,368August
              
              
              13.68
              
              
              
              12.40
              
              
              
              38,951,248September
              
              
              15.84
              
              
              
              12.28
              
              
              
              58,719,664October
              
              
              18.24
              
              
              
              14.07
              
              
              
              78,045,184November
              
              
              18.48
              
              
              
              16.27
              
              
              
              52,157,108December
              
              
              18.18
              
              
              
              16.43
              
              
              
              39,525,544
  36
  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).
 
 TSXDebenture price
                ($)
              
              
              Debenture price
                ($)Period
              
              High
              
              
              Low
              
              
              VolumeJanuary
              
              
              98.00
              
              
              
              90.00
              
              
              
              1,550February
              
              
              99.45
              
              
              
              91.51
              
              
              
              1,070March
              
              
              95.00
              
              
              
              88.00
              
              
              
              24,470April
              
              
              99.46
              
              
              
              91.51
              
              
              
              16,420May
              
              
              100.00
              
              
              
              96.50
              
              
              
              23,870June
              
              
              101.00
              
              
              
              95.00
              
              
              
              10,610July
              
              
              100.50
              
              
              
              98.50
              
              
              
              6,600August
              
              
              102.00
              
              
              
              100.00
              
              
              
              14,000September
              
              
              102.50
              
              
              
              100.30
              
              
              
              10,960October
              
              
              101.50
              
              
              
              100.10
              
              
              
              22,880November
              
              
              103.00
              
              
              
              101.30
              
              
              
              5,360December
              
              
              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 $100 principal amount of 6.5% 2005 Debentures).
  37
  TSXDebenture price
                ($)
              
              
              Debenture price
                ($)Period
              
              High
              
              
              Low
              
              
              VolumeJanuary
              
              
              100.00
              
              
              
              85.00
              
              
              
              3,700February
              
              
              100.00
              
              
              
              93.00
              
              
              
              4,850March
              
              
              100.00
              
              
              
              91.00
              
              
              
              2,660April
              
              
              100.00
              
              
              
              97.00
              
              
              
              2,340May
              
              
              100.00
              
              
              
              97.50
              
              
              
              7,800June
              
              
              103.00
              
              
              
              99.65
              
              
              
              2,690July
              
              
              101.00
              
              
              
              100.00
              
              
              
              1,780August
              
              
              101.50
              
              
              
              100.75
              
              
              
              1,020September
              
              
              102.00
              
              
              
              100.75
              
              
              
              2,890October
              
              
              102.45
              
              
              
              100.76
              
              
              
              3,760November
              
              
              102.25
              
              
              
              101.53
              
              
              
              2,910December
              
              
              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).
 
 TSXDebenture price
                ($)
              
              
              Debenture price
                ($)Period
              
              High
              
              
              Low
              
              
              VolumeJanuary
              
              
              94.00
              
              
              
              82.00
              
              
              
              131,940February
              
              
              93.00
              
              
              
              87.00
              
              
              
              220,230March
              
              
              93.00
              
              
              
              84.50
              
              
              
              92,770April
              
              
              96.00
              
              
              
              91.50
              
              
              
              16,420May
              
              
              98.25
              
              
              
              95.50
              
              
              
              47,090June
              
              
              99.85
              
              
              
              97.75
              
              
              
              57,130July
              
              
              100.60
              
              
              
              97.00
              
              
              
              41,720August
              
              
              101.50
              
              
              
              99.75
              
              
              
              35,760September
              
              
              102.00
              
              
              
              100.50
              
              
              
              25,860October
              
              
              102.90
              
              
              
              100.25
              
              
              
              24,250November
              
              
              103.00
              
              
              
              102.00
              
              
              
              16,090December
              
              
              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.
  38
  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.
  39
  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.
  40
  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.
  41
  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
      Programproviding 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 Programproviding a royalty reduction for coalbed gas
      wells with average daily production less than 17,000 m3as 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;
  42
  ·
              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, 2002providing reduced Crown royalty and freehold tax rates on incentive
      volumes of 8,000 m3for deep development vertical oil wells, 4,000 m3for non-deep exploratory vertical oil wells, and 16,000 m3for deep exploratory vertical oil wells (more than 1,700 metres or
      within certain formations);
  43
  ·
              Royalty/Tax Incentive Volumes
      for Exploratory Gas Wells Drilled on or after October 1, 2002providing 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, 2002providing 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.
  44
  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 Incentiveprovides 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.
  45
  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 Actcame into effect on July 1, 2007 ("CCEMAA") and was amended by
the Climate Change and
Emissions Management Amendment Acton 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.
  46
  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 CO2equivalent
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.
  47
  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-situproduction 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.
  48
  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 1994and 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 CO2enhanced
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.
  49
  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 CO2injection
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.
  50
  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.
  51
  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.
  52
  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.
  53
  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.
  54
  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.
  55
  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.
  56
  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.
 
 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 $14billion (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.
 
 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.
 
 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.
  57
  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 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).
  58
  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.
  59
  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.
  60
  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.
  61
  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.
  62
  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 CO2supply 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
      CO2EOR 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;
  63
  ·
              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.
  64
  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.
  65
  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.
  66
  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 ratashare 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.
  67
  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 areturn 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";
  68
  (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.
  69
  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).
  70
  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. NunnsChief
      Executive Officer
              President
      and Chief Operating Officer(signed)
      Daryl Gilbert
              (signed)
      Jack SchanckDirector
      and Chairmanof the Reserves
      Committee
              Director
      and Member of the Reserves CommitteeMarch
      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).
 
 3.
              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).
 
 4.
              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.
 
 5.
              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)Audited
              
              
              Evaluated
              
              
              Reviewed
              
              
              TotalGLJ Petroleum
                Consultants Ltd.
              February 11, 2010
              Canada
              
              $
              -
              
              
              $
              5,537
              
              
              $
              -
              
              
              $
              5,537Sproule Associates Limited
              February 24, 2010
              Canada
              
              $
              1,735
              
              
              $
              4,312
              
              
              $
              -
              
              
              $
              6,047Sproule 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
 
 RESERVESLIGHT AND MEDIUM OIL
                
                
                HEAVY OILRESERVES CATEGORY
                
                Gross
                    (MMbbl)
                
                
                Net
                    (MMbbl)
                
                
                Gross
                    (MMbbl)
                
                
                Net
                    (MMbbl)PROVEDDeveloped
      Producing
                
                
                211
                
                
                
                181
                
                
                
                53
                
                
                
                48Developed
      Non-Producing
                
                
                4
                
                
                
                3
                
                
                
                1
                
                
                
                1Undeveloped
                
                
                46
                
                
                
                40
                
                
                
                2
                
                
                
                1TOTAL
      PROVED
                
                
                261
                
                
                
                224
                
                
                
                56
                
                
                
                51PROBABLE
                
                
                107
                
                
                
                91
                
                
                
                15
                
                
                
                13TOTAL
      PROVED PLUS PROBABLE
                
                
                368
                
                
                
                316
                
                
                
                71
                
                
                
                64
 
 
 RESERVESNATURAL GAS
                
                
                NATURAL GAS LIQUIDSRESERVES CATEGORY
                
                Gross
                    (Bcf)
                
                
                Net
                    (Bcf)
                
                
                Gross
                    (MMbbl)
                
                
                Net
                    (MMbbl)PROVEDDeveloped
      Producing
                
                
                828
                
                
                
                713
                
                
                
                22
                
                
                
                16Developed
      Non-Producing
                
                
                49
                
                
                
                39
                
                
                
                1
                
                
                
                1Undeveloped
                
                
                61
                
                
                
                54
                
                
                
                1
                
                
                
                1TOTAL
      PROVED
                
                
                938
                
                
                
                807
                
                
                
                24
                
                
                
                17PROBABLE
                
                
                354
                
                
                
                299
                
                
                
                9
                
                
                
                6TOTAL
      PROVED PLUS PROBABLE
                
                
                1,292
                
                
                
                1,105
                
                
                
                33
                
                
                
                24
 
 
 RESERVESTOTAL OIL EQUIVALENTRESERVES CATEGORY
              
              Gross
                  (MMboe)
              
              
              Net
                  (MMboe)PROVEDDeveloped
      Producing
              
              
              423
              
              
              
              364Developed
      Non-Producing
              
              
              14
              
              
              
              12Undeveloped
              
              
              59
              
              
              
              51TOTAL
      PROVED
              
              
              497
              
              
              
              426PROBABLE
              
              
              190
              
              
              
              161TOTAL
      PROVED PLUS PROBABLE
              
              
              687
              
              
              
              587
  2
  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)PROVEDDeveloped
      Producing
              
              
              14,235
              
              
              
              10,092
              
              
              
              7,913
              
              
              
              6,572
              
              
              
              5,658
              
              
              
              21.76
              
              
              
              3.63Developed
      Non-Producing
              
              
              411
              
              
              
              309
              
              
              
              245
              
              
              
              203
              
              
              
              173
              
              
              
              21.08
              
              
              
              3.51Undeveloped
              
              
              2,417
              
              
              
              1,345
              
              
              
              830
              
              
              
              541
              
              
              
              362
              
              
              
              16.22
              
              
              
              2.70TOTAL
      PROVED
              
              
              17,063
              
              
              
              11,746
              
              
              
              8,989
              
              
              
              7,315
              
              
              
              6,193
              
              
              
              21.08
              
              
              
              3.51PROBABLE
              
              
              8,461
              
              
              
              4,294
              
              
              
              2,635
              
              
              
              1,802
              
              
              
              1,321
              
              
              
              16.38
              
              
              
              2.73TOTAL
      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$)PROVEDDeveloped
      Producing
              
              
              12,505
              
              
              
              9,158
              
              
              
              7,340
              
              
              
              6,192
              
              
              
              5,394Developed
      Non-Producing
              
              
              306
              
              
              
              236
              
              
              
              191
              
              
              
              162
              
              
              
              140Undeveloped
              
              
              1,778
              
              
              
              982
              
              
              
              597
              
              
              
              379
              
              
              
              244TOTAL
      PROVED
              
              
              14,589
              
              
              
              10,376
              
              
              
              8,128
              
              
              
              6,733
              
              
              
              5,778PROBABLE
              
              
              6,116
              
              
              
              3,109
              
              
              
              1,908
              
              
              
              1,306
              
              
              
              958TOTAL
      PROVED PLUS PROBABLE
              
              
              20,705
              
              
              
              13,485
              
              
              
              10,037
              
              
              
              8,039
              
              
              
              6,736
  3
  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
              
              
              
              14,589Proved
      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
              
              
              
              3.51Heavy
      Oil(1)
              
              
              1,199
              
              
              
              22.02
              
              
              
              3.67Natural
      Gas(2)
              
              
              888
              
              
              
              21.52
              
              
              
              3.59Non-Conventional
      Oil and Gas Activities
              
              
              70
              
              
              
              10.90
              
              
              
              1.82TOTAL
              
              
              8,989
              
              
              
              21.08
              
              
              
              3.51Proved
      Plus Probable Reserves
              
              Light
      and Medium Crude Oil(1)
              
              
              8,993
              
              
              
              19.80
              
              
              
              3.30Heavy
      Oil(1)
              
              
              1,452
              
              
              
              21.12
              
              
              
              3.52Natural
      Gas(2)
              
              
              1,077
              
              
              
              19.75
              
              
              
              3.29Non-Conventional
      Oil and Gas Activities
              
              
              101
              
              
              
              10.33
              
              
              
              1.72TOTAL
              
              
              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.
  4
  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 reservesare
      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.
  5
  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.
  6
  SUMMARY
OF PRICING AND INFLATION RATE ASSUMPTIONS
 as of
December 31, 2009
 FORECAST
PRICES AND COSTS
 
 OIL
              
              
              
              
              
              EDMONTON
      LIQUIDS PRICESYear
              
              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)Forecast2010
              
              
              79.58
              
              
              
              83.75
              
              
              
              72.25
              
              
              
              78.32
              
              
              
              5.66
              
              
              
              52.60
              
              
              
              61.88
              
              
              
              85.61
              
              
              
              -
              
              
              
              0.942011
              
              
              83.73
              
              
              
              88.20
              
              
              
              74.79
              
              
              
              81.61
              
              
              
              6.50
              
              
              
              55.39
              
              
              
              65.13
              
              
              
              90.15
              
              
              
              2
              %
              
              
              0.942012
              
              
              86.45
              
              
              
              91.09
              
              
              
              74.49
              
              
              
              82.91
              
              
              
              6.67
              
              
              
              57.20
              
              
              
              67.28
              
              
              
              93.11
              
              
              
              2
              %
              
              
              0.942013
              
              
              89.60
              
              
              
              94.46
              
              
              
              75.84
              
              
              
              85.04
              
              
              
              7.09
              
              
              
              59.32
              
              
              
              69.76
              
              
              
              96.55
              
              
              
              2
              %
              
              
              0.942014
              
              
              92.00
              
              
              
              97.01
              
              
              
              77.38
              
              
              
              86.83
              
              
              
              7.52
              
              
              
              60.93
              
              
              
              71.66
              
              
              
              99.16
              
              
              
              2
              %
              
              
              0.942015
              
              
              93.84
              
              
              
              98.98
              
              
              
              78.94
              
              
              
              88.59
              
              
              
              7.66
              
              
              
              62.16
              
              
              
              73.11
              
              
              
              101.16
              
              
              
              2
              %
              
              
              0.942016
              
              
              95.72
              
              
              
              100.97
              
              
              
              80.54
              
              
              
              90.37
              
              
              
              7.88
              
              
              
              63.41
              
              
              
              74.58
              
              
              
              103.20
              
              
              
              2
              %
              
              
              0.942017
              
              
              97.64
              
              
              
              103.01
              
              
              
              82.16
              
              
              
              92.20
              
              
              
              8.24
              
              
              
              64.69
              
              
              
              76.09
              
              
              
              105.29
              
              
              
              2
              %
              
              
              0.942018
              
              
              99.59
              
              
              
              105.09
              
              
              
              83.83
              
              
              
              94.06
              
              
              
              8.62
              
              
              
              66.00
              
              
              
              77.63
              
              
              
              107.41
              
              
              
              2
              %
              
              
              0.942019
              
              
              101.58
              
              
              
              107.21
              
              
              
              85.51
              
              
              
              95.96
              
              
              
              8.80
              
              
              
              67.33
              
              
              
              79.19
              
              
              
              109.58
              
              
              
              2
              %
              
              
              0.94Thereafter
              
              
              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
    CostsYear
              
              Proved Reserves (MM$)
              
              
              Proved Plus Probable Reserves
      (MM$)2010
              
              
              342
              
              
              
              4482011
              
              
              302
              
              
              
              4532012
              
              
              143
              
              
              
              3492013
              
              
              85
              
              
              
              2152014
              
              
              49
              
              
              
              106Total:
      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.
  7
  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
                
                
                
                1,476Extensions
                
                
                12
                
                
                
                21
                
                
                
                34
                
                
                
                -
                
                
                
                -
                
                
                
                -
                
                
                
                21
                
                
                
                8
                
                
                
                29Improved
      Recovery(1)
                
                
                7
                
                
                
                -
                
                
                
                6
                
                
                
                2
                
                
                
                -
                
                
                
                2
                
                
                
                4
                
                
                
                1
                
                
                
                5Technical
      Revisions
                
                
                1
                
                
                
                (5
                )
                
                
                (4
                )
                
                
                11
                
                
                
                (3
                )
                
                
                8
                
                
                
                24
                
                
                
                (38
                )
                
                
                (14
                )Discoveries
                
                
                -
                
                
                
                -
                
                
                
                -
                
                
                
                -
                
                
                
                -
                
                
                
                -
                
                
                
                2
                
                
                
                1
                
                
                
                4Acquisitions
                
                
                4
                
                
                
                2
                
                
                
                6
                
                
                
                -
                
                
                
                -
                
                
                
                -
                
                
                
                8
                
                
                
                4
                
                
                
                12Dispositions
                
                
                (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
              
              
              3
              
              
              
              1
              
              
              
              5
              
              
              
              2
              
              
              
              -
              
              
              
              2
              
              
              
              2
              
              
              
              1
              
              
              
              3
  8
  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
              
              
              
              729Extensions
              
              
              1
              
              
              
              -
              
              
              
              1
              
              
              
              16
              
              
              
              23
              
              
              
              39Improved
      Recovery(1)
              
              
              -
              
              
              
              -
              
              
              
              -
              
              
              
              9
              
              
              
              -
              
              
              
              10Technical
      Revisions
              
              
              -
              
              
              
              (1
              )
              
              
              -
              
              
              
              17
              
              
              
              (15
              )
              
              
              2Discoveries
              
              
              -
              
              
              
              -
              
              
              
              -
              
              
              
              -
              
              
              
              -
              
              
              
              1Acquisitions
              
              
              -
              
              
              
              -
              
              
              
              -
              
              
              
              5
              
              
              
              3
              
              
              
              8Dispositions
              
              
              (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
              
              
              -
              
              
              
              -
              
              
              
              -
              
              
              
              6
              
              
              
              2
              
              
              
              8
 
 (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 twoyears 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.
  9
  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
EndPrior
      thereto
                
                
                33,447
                
                
                
                33,447
                
                
                
                1,839
                
                
                
                1,839
                
                
                
                43,433
                
                
                
                43,433
                
                
                
                1,452
                
                
                
                1,4522007
                
                
                5,313
                
                
                
                34,496
                
                
                
                636
                
                
                
                1,041
                
                
                
                11,665
                
                
                
                38,483
                
                
                
                294
                
                
                
                1,1002008
                
                
                8,911
                
                
                
                36,872
                
                
                
                5,429
                
                
                
                5,672
                
                
                
                44,354
                
                
                
                62,311
                
                
                
                314
                
                
                
                1,1102009
                
                
                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
EndPrior
      thereto
                
                
                22,466
                
                
                
                22,466
                
                
                
                974
                
                
                
                974
                
                
                
                32,749
                
                
                
                32,749
                
                
                
                1,745
                
                
                
                1,7452007
                
                
                5,290
                
                
                
                24,160
                
                
                
                729
                
                
                
                1,432
                
                
                
                10,896
                
                
                
                25,619
                
                
                
                257
                
                
                
                1,8362008
                
                
                11,175
                
                
                
                32,161
                
                
                
                13,543
                
                
                
                13,361
                
                
                
                57,360
                
                
                
                79,269
                
                
                
                504
                
                
                
                2,0422009
                
                
                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.
  10
  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
              
              
              
              326Anticipated
      to be paid in 2010
              
              
              55
              
              
              
              50Anticipated
      to be paid in 2011
              
              
              57
              
              
              
              47Anticipated
      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.
  11
  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
              
              
              TotalSouthern
              
              
              29,617
              
              
              
              54
              
              
              
              38,666
              
              
              
              163
              
              
              
              175
              
              
              
              192
              
              
              
              910
              
              
              
              752
              
              
              
              1,662Eastern
              
              
              23,506
              
              
              
              44
              
              
              
              30,789
              
              
              
              73
              
              
              
              90
              
              
              
              88
              
              
              
              731
              
              
              
              249
              
              
              
              980Central
              
              
              29,685
              
              
              
              183
              
              
              
              60,085
              
              
              
              147
              
              
              
              560
              
              
              
              240
              
              
              
              1,209
              
              
              
              253
              
              
              
              1,462NW
      Alberta
              
              
              17,694
              
              
              
              37
              
              
              
              23,844
              
              
              
              78
              
              
              
              103
              
              
              
              95
              
              
              
              514
              
              
              
              465
              
              
              
              979Northern
              
              
              3,471
              
              
              
              122
              
              
              
              23,837
              
              
              
              12
              
              
              
              364
              
              
              
              73
              
              
              
              683
              
              
              
              706
              
              
              
              1,389Total
              
              
              103,973
              
              
              
              440
              
              
              
              177,221
              
              
              
              472
              
              
              
              1,292
              
              
              
              687
              
              
              
              4,047
              
              
              
              2,425
              
              
              
              6,47259%
      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.
  12
  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, Wyomingand
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.
  13
  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 CO2to 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.
  14
  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
              
              
              TotalOil
              
              
              GasGross
              
              
              Net
              
              
              Gross
              
              
              Net
              
              
              Gross
              
              
              Net
              
              
              Gross
              
              
              NetAlberta
              
              
              9,862
              
              
              
              5,485
              
              
              
              9,560
              
              
              
              3,950
              
              
              
              6,523
              
              
              
              3,514
              
              
              
              25,945
              
              
              
              12,949British
      Columbia
              
              
              145
              
              
              
              50
              
              
              
              979
              
              
              
              468
              
              
              
              418
              
              
              
              145
              
              
              
              1,542
              
              
              
              663Saskatchewan
              
              
              7,670
              
              
              
              4,960
              
              
              
              1,224
              
              
              
              683
              
              
              
              3,078
              
              
              
              1,452
              
              
              
              11,972
              
              
              
              7,095Manitoba
              
              
              715
              
              
              
              339
              
              
              
              1
              
              
              
              -
              
              
              
              217
              
              
              
              105
              
              
              
              933
              
              
              
              444Northwest
      Territories
              
              
              3
              
              
              
              -
              
              
              
              7
              
              
              
              1
              
              
              
              37
              
              
              
              7
              
              
              
              47
              
              
              
              8Wyoming
              
              
              -
              
              
              
              -
              
              
              
              301
              
              
              
              124
              
              
              
              68
              
              
              
              23
              
              
              
              369
              
              
              
              147Montana
              
              
              5
              
              
              
              2
              
              
              
              -
              
              
              
              -
              
              
              
              -
              
              
              
              -
              
              
              
              5
              
              
              
              2North
      Dakota
              
              
              16
              
              
              
              6
              
              
              
              1
              
              
              
              -
              
              
              
              -
              
              
              
              -
              
              
              
              17
              
              
              
              6Total
              
              
              18,416
              
              
              
              10,842
              
              
              
              12,073
              
              
              
              5,226
              
              
              
              10,341
              
              
              
              5,246
              
              
              
              40,830
              
              
              
              21,314
  15
  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
              
              
              NetAlberta
              
              
              1,431
              
              
              
              1,120British
      Columbia
              
              
              697
              
              
              
              524Saskatchewan
              
              
              635
              
              
              
              530Manitoba
              
              
              206
              
              
              
              201Northwest
      Territories
              
              
              92
              
              
              
              18Wyoming
              
              
              16
              
              
              
              8Montana
              
              
              3
              
              
              
              2North
      Dakota
              
              
              26
              
              
              
              22Total
              
              
              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.
  16
  2009
                  MM$Property
      Acquisitions (Dispositions)Proved
      Properties
              
              
              (369
              )Unproved
      Properties
              
              
              19Exploration
      Costs(1)
              
              
              79Development
      Costs(2)
              
              
              546Corporate
      Costs
              
              
              44Total
      Capital Expenditures
              
              
              319Corporate
      Acquisitions
              
              
              116Total
      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 WellsGross
              
              
              Net
              
              
              Gross
              
              
              NetOil
              
              
              6
              
              
              
              5
              
              
              
              96
              
              
              
              63Natural
      Gas
              
              
              10
              
              
              
              7
              
              
              
              30
              
              
              
              10Service
              
              
              1
              
              
              
              1
              
              
              
              10
              
              
              
              6Dry
              
              
              -
              
              
              
              -
              
              
              
              2
              
              
              
              2Total
              
              
              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
                  
                  
                  NetProved
      Developed Producing
                  
                  
                  60,841
                  
                  
                  
                  51,286
                  
                  
                  
                  17,925
                  
                  
                  
                  15,472
                  
                  
                  
                  357,969
                  
                  
                  
                  301,029
                  
                  
                  
                  9,185
                  
                  
                  
                  6,589
                  
                  
                  
                  147,613
                  
                  
                  
                  123,519Proved
      Developed Non-Producing
                  
                  
                  994
                  
                  
                  
                  865
                  
                  
                  
                  322
                  
                  
                  
                  272
                  
                  
                  
                  12,945
                  
                  
                  
                  10,389
                  
                  
                  
                  216
                  
                  
                  
                  166
                  
                  
                  
                  3,689
                  
                  
                  
                  3,035Proved
      Undeveloped
                  
                  
                  3,656
                  
                  
                  
                  3,603
                  
                  
                  
                  546
                  
                  
                  
                  514
                  
                  
                  
                  3,105
                  
                  
                  
                  2,759
                  
                  
                  
                  458
                  
                  
                  
                  437
                  
                  
                  
                  5,177
                  
                  
                  
                  5,014Total
      Proved
                  
                  
                  65,491
                  
                  
                  
                  55,754
                  
                  
                  
                  18,792
                  
                  
                  
                  16,258
                  
                  
                  
                  374,019
                  
                  
                  
                  314,177
                  
                  
                  
                  9,860
                  
                  
                  
                  7,193
                  
                  
                  
                  156,480
                  
                  
                  
                  131,567Total
      Probable
                  
                  
                  3,309
                  
                  
                  
                  2,741
                  
                  
                  
                  647
                  
                  
                  
                  503
                  
                  
                  
                  24,981
                  
                  
                  
                  19,379
                  
                  
                  
                  544
                  
                  
                  
                  400
                  
                  
                  
                  8,664
                  
                  
                  
                  6,873Total
      Proved Plus Probable
                  
                  
                  68,800
                  
                  
                  
                  58,495
                  
                  
                  
                  19,439
                  
                  
                  
                  16,761
                  
                  
                  
                  399,000
                  
                  
                  
                  333,556
                  
                  
                  
                  10,404
                  
                  
                  
                  7,592
                  
                  
                  
                  165,143
                  
                  
                  
                  138,440
 
 17
  No one
field accounts for more thanfourpercent 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
      EndedMarch 31
              
              
              June 30
              
              
              September 30
              
              
              December 31
              
              
              December 31,
2009Average
      Daily Production(1)Light
      and Medium Crude Oil (bbl/d)
              
              
              67,864
              
              
              
              68,148
              
              
              
              67,666
              
              
              
              67,371
              
              
              
              67,760Heavy
      Oil (bbl/d)
              
              
              26,328
              
              
              
              26,456
              
              
              
              27,070
              
              
              
              24,009
              
              
              
              25,962Gas
      (MMcf/d)
              
              
              447
              
              
              
              459
              
              
              
              441
              
              
              
              411
              
              
              
              440NGLs
      (bbl/d)
              
              
              11,452
              
              
              
              9,466
              
              
              
              9,847
              
              
              
              10,256
              
              
              
              10,251Combined
      (boe/d)
              
              
              180,096
              
              
              
              180,601
              
              
              
              178,124
              
              
              
              170,164
              
              
              
              177,221Average
      Net Production Prices ReceivedLight
      and Medium Crude Oil ($/bbl)
              
              
              45.98
              
              
              
              60.85
              
              
              
              67.41
              
              
              
              72.66
              
              
              
              61.79Heavy
      Oil ($/bbl)
              
              
              36.92
              
              
              
              56.71
              
              
              
              58.72
              
              
              
              62.97
              
              
              
              53.75Gas
      ($/Mcf)
              
              
              5.37
              
              
              
              3.68
              
              
              
              3.13
              
              
              
              4.39
              
              
              
              4.13NGLs
      ($/bbl)
              
              
              35.73
              
              
              
              38.37
              
              
              
              41.74
              
              
              
              48.71
              
              
              
              41.07Combined
      ($/boe)
              
              
              38.30
              
              
              
              42.62
              
              
              
              44.58
              
              
              
              51.19
              
              
              
              44.11Royalties
      PaidLight
      and Medium Crude Oil ($/bbl)
              
              
              6.87
              
              
              
              10.10
              
              
              
              11.38
              
              
              
              13.71
              
              
              
              10.53Heavy
      Oil ($/bbl)
              
              
              3.88
              
              
              
              7.17
              
              
              
              8.55
              
              
              
              9.52
              
              
              
              7.26Gas
      ($/Mcf)
              
              
              1.22
              
              
              
              0.63
              
              
              
              0.45
              
              
              
              0.69
              
              
              
              0.75NGLs
      ($/bbl)
              
              
              9.67
              
              
              
              13.09
              
              
              
              12.08
              
              
              
              15.06
              
              
              
              12.40Combined
      ($/boe)
              
              
              6.80
              
              
              
              7.14
              
              
              
              7.41
              
              
              
              9.35
              
              
              
              7.66Production
      Costs(2)(3)Light
      and Medium Crude Oil ($/bbl)
              
              
              20.51
              
              
              
              20.71
              
              
              
              20.55
              
              
              
              20.34
              
              
              
              20.53Heavy
      Oil ($/bbl)
              
              
              15.79
              
              
              
              15.62
              
              
              
              15.37
              
              
              
              15.37
              
              
              
              15.54Gas
      ($/Mcf)
              
              
              1.56
              
              
              
              1.51
              
              
              
              1.56
              
              
              
              1.63
              
              
              
              1.57NGLs
      ($/bbl)
              
              
              15.87
              
              
              
              16.12
              
              
              
              15.98
              
              
              
              15.80
              
              
              
              15.94Combined
      ($/boe)
              
              
              14.93
              
              
              
              14.79
              
              
              
              14.90
              
              
              
              15.10
              
              
              
              14.93TransportationLight
      and Medium Crude Oil ($/bbl)
              
              
              -
              
              
              
              -
              
              
              
              -
              
              
              
              -
              
              
              
              -Heavy
      Oil ($/bbl)
              
              
              0.05
              
              
              
              0.06
              
              
              
              0.06
              
              
              
              0.07
              
              
              
              0.06Gas
      ($/Mcf)
              
              
              0.21
              
              
              
              0.20
              
              
              
              0.21
              
              
              
              0.21
              
              
              
              0.21NGLs
      ($/bbl)
              
              
              -
              
              
              
              -
              
              
              
              -
              
              
              
              -
              
              
              
              -Combined
      ($/boe)
              
              
              0.54
              
              
              
              0.51
              
              
              
              0.53
              
              
              
              0.52
              
              
              
              0.52(Gain)/Loss
      on Risk Management ContractsLight
      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
              
              
              
              40.16Heavy
      Oil ($/bbl)
              
              
              17.20
              
              
              
              33.86
              
              
              
              34.74
              
              
              
              38.01
              
              
              
              30.89Gas
      ($/Mcf)
              
              
              3.15
              
              
              
              2.00
              
              
              
              1.73
              
              
              
              2.35
              
              
              
              2.29NGLs
      ($/bbl)
              
              
              10.18
              
              
              
              9.16
              
              
              
              13.69
              
              
              
              17.86
              
              
              
              12.73Combined
      ($/boe)
              
              
              25.66
              
              
              
              25.64
              
              
              
              25.91
              
              
              
              28.11
              
              
              
              26.32
  18
  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.
  19
  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
              
              
              2008Light
      and Medium Oil and NGLs
              
              
              Heavy
      Oil
              
              
              Light
      and Medium Oil and NGLs
              
              
              Heavy
      OilQuarter ended
              
              ($/bbl)
              
              
              ($/bbl)
              
              
              ($/bbl)
              
              
              ($/bbl)March
      31
              
              
              44.50
              
              
              
              36.92
              
              
              
              88.77
              
              
              
              66.64June
      30
              
              
              58.11
              
              
              
              56.71
              
              
              
              111.88
              
              
              
              93.12September
      30
              
              
              64.15
              
              
              
              58.72
              
              
              
              110.45
              
              
              
              98.07December
      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.
  20
  APPENDIX
B
 
 MANDATE
OF THE AUDIT COMMITTEE
 
 1.
              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:
  2
  (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.
  3
  (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.
  4
  5.
              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.
 
 6.
              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.
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  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.
 
 9.
              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.
  6
  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.
   7