Exhibit
99.1




PENN
WEST ENERGY TRUST
  Revised
Annual Information Form
 for
the year ended December 31, 2008
  
  
  
 
  
  
  
  March
26, 2009*
  *(Except for: (i) page 12 of
Appendix A-3, on which the table reflecting (among other things) proved plus
probable gross reserves by major operating region as at December 31, 2008
has been revised to correct typographical errors in the allocation of proved
plus probable gross reserves among such regions; (ii) Appendix A-1: Report of
Management and Directors on Reserves Data and Other Information; and (iii)
Appendix A-2: Report on Reserves Data; each of which is dated as of September
15, 2009.)
    
    TABLE OF
      CONTENTSPageGLOSSARY OF
      TERMS
              3CONVENTIONS
              6ABBREVIATIONS
              6CONVERSIONS
              8SPECIAL NOTE
      REGARDING FORWARD-LOOKING STATEMENTS
              9NON-GAAP
      MEASURES
              10EFFECTIVE DATE OF
      INFORMATION
              10PENN WEST ENERGY
      TRUST
              11GENERAL DEVELOPMENT
      OF THE BUSINESS
              13DESCRIPTION OF OUR
      BUSINESS
              18CAPITALIZATION OF
      PWPL
              18INFORMATION RELATING
      TO PENN WEST
              20CORPORATE
      GOVERNANCE
              28AUDIT COMMITTEE
      DISCLOSURES
              34DISTRIBUTIONS TO
      UNITHOLDERS
              36MARKET FOR
      SECURITIES
              36INDUSTRY
      CONDITIONS
              40RISK
      FACTORS
              48MATERIAL
      CONTRACTS
              68LEGAL PROCEEDINGS
      AND REGULATORY ACTIONS
              68TRANSFER AGENTS AND
      REGISTRARS
              69INTEREST OF
      MANAGEMENT AND OTHERS IN MATERIAL TRANSACTIONS
              69INTERESTS OF
      EXPERTS
              69ADDITIONAL
      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
 
   2
  GLOSSARY OF TERMS
  The
following is a glossary of certain terms used in this Annual Information
Form.
  "6.5% 2005 Debenture Indenture"
means the trust indenture governing the 6.5% 2005 Debentures.
  "6.5% 2005 Debentures" means
the 6.5% convertible, extendible, unsecured, subordinated debentures issued on
May 26, 2005 pursuant to the 6.5% 2005 Debenture Indenture, which debentures
were assumed by Penn West pursuant to the Canetic Acquisition and subsequently
began trading on the TSX as securities of Penn West on January 16, 2008 under
the symbol PWT.DB.D.
  "6.5% 2006 Debenture Indenture"
means the trust indenture governing the 6.5% 2006 Debentures.
  "6.5% 2006 Debentures" means
the 6.5% convertible, extendible, unsecured, subordinated debentures issued on
August 24, 2006 pursuant to the 6.5% 2006 Debenture Indenture, which debentures
were assumed by Penn West pursuant to the Canetic Acquisition and subsequently
began trading on the TSX as securities of Penn West on January 16, 2008 under
the symbol PWT.DB.F.
  "7.2% Debenture Indenture"
means the trust indenture governing the 7.2% Debentures.
  "7.2% Debentures" means the
7.2% convertible, unsecured, subordinated debentures issued on May 2, 2006
pursuant to the 7.2% Debenture Indenture, which debentures were assumed by Penn
West pursuant to the Vault Acquisition and subsequently began trading on the TSX
as securities of Penn West on January 15, 2008 under the symbol
PWT.DB.E.
  "8% 2004 Debenture Indenture"
means the trust indenture governing the 8% 2004 Debentures.
  "8% 2004 Debentures" means the
8% convertible, extendible, unsecured, subordinated debentures issued on June
15, 2004 pursuant to the 8% 2004 Debenture Indenture, which debentures were
assumed by Penn West pursuant to the Canetic Acquisition and subsequently began
trading on the TSX as securities of Penn West on January 16, 2008 under the
symbol PWT.DB.B.
  "8% 2005 Debenture Indenture"
means the trust indenture governing the 8% 2005 Debentures.
  "8% 2005 Debentures" means the
8% convertible, unsecured, subordinated debentures issued on June 22, 2005
pursuant to the 8% 2005 Debenture Indenture, which debentures were assumed by
Penn West pursuant to the Vault Acquisition and subsequently began trading on
the TSX as securities of Penn West on January 15, 2008 under the symbol
PWT.DB.C.
  "2007 Senior Notes" has the
meaning ascribed thereto under "General Development of the Business – History
and Development – Year Ended December 31, 2007 – Private Placement of 2007
Senior Notes".
  "2008 Senior Notes" has the
meaning ascribed thereto under "General Development of the Business – History
and Development – Year Ended December 31, 2008 – Private Placement of 2008
Senior Notes".
  "2008 Pounds Sterling Senior
Notes" has the meaning ascribed thereto under "General Development of the
Business – History and Development – Year Ended December 31, 2008 – Private
Placement of 2008 Pounds Sterling Senior Notes".
  "ABCA" means the Business Corporations Act
(Alberta), R.S.A. 2000, C. B-9, as amended, including the regulations
promulgated thereunder.
  "Administration Agreement"
means the agreement dated May 31, 2005 between the Trustee and PWPL pursuant to
which PWPL agrees to provide certain administrative and advisory services in
connection with Penn West.
  "Board of Directors" means the
Board of Directors of PWPL.
  "Canadian GAAP" means Canadian
generally accepted accounting principles.
  3
  "Canetic" means Canetic
Resources Trust, a trust established under the laws of the Province of
Alberta.
  "Canetic Acquisition" means the
plan of arrangement under the ABCA pursuant to which Penn West acquired Canetic
on January 11, 2008.
  "CBM" means coalbed
methane.
  "Convertible Debentures" means,
collectively, the 6.5% 2005 Debentures, the 6.5% 2006 Debentures, the 7.2%
Debentures, the 8% 2004 Debentures and the 8% 2005 Debentures.
  "Debenture Indentures" means,
collectively, the 6.5% 2005 Debenture Indenture, the 6.5% 2006 Debenture
Indenture, the 7.2% Debenture Indenture, the 8% 2004 Debenture Indenture and the
8% 2005 Debenture Indenture.
  "Debenture Trustee" means, in
respect of the 6.5% 2005 Debentures, Olympia Trust Company, in respect of each
of the 6.5% 2006 Debentures and the 8% 2004 Debentures, Computershare Trust
Company of Canada, and in respect of each of the 7.2% Debentures and the 8% 2005
Debentures, Canadian Western Trust Company.
  "Endev" means Endev Energy
Inc., a corporation incorporated under the laws of the Province of
Alberta.
  "Endev Acquisition" means the
plan of arrangement under the ABCA pursuant to which Penn West acquired Endev on
July 22, 2008.
  "Engineering Reports" means,
collectively, the GLJ Report and the Sproule Report.
  "Form 40-F" means our Annual
Report on Form 40-F for the fiscal year ended December 31, 2008, filed with the
SEC.
  "GLJ" means GLJ Petroleum
Consultants Ltd., independent petroleum consultants of Calgary,
Alberta.
  "GLJ Report" means the report
prepared by GLJ dated February 24, 2009 evaluating approximately 60% of the
crude oil, natural gas and natural gas liquids reserves and the net present
value of future net revenue attributable to those reserves effective as at
December 31, 2008.
  "Gross" means:
  (a)
              in
      relation to our interest in production or reserves, our working interest
      (operating or non-operating) share before deduction of royalties and
      without including any royalty interests of
ours;
  (b)
              in
      relation to wells, the total number of wells in which we have an interest;
      and
  (c)
              in
      relation to properties, the total area of properties in which we have an
      interest.
  "Internal Notes" means the
unsecured subordinated promissory notes issued by PWPL and certain other
Operating Entities to Penn West.
  "Net" means:
  (a)
              in
      relation to our interest in production or reserves, our working interest
      (operating or non-operating) share after deduction of royalty obligations,
      plus our royalty interests in production or
  reserves;
  (b)
              in
      relation to our interest in wells, the number of wells obtained by
      aggregating our working interest in each of our gross wells;
      and
  (c)
              in
      relation to our interest in a property, the total area in which we have an
      interest multiplied by the working interest we
  owned.
   4
  "NI 51-101" means National
Instrument 51-101 – Standards of Disclosure for Oil and Gas
Activities.
  "Non-Resident" means: (i) a
person who is not a resident of Canada for the purposes of the Tax Act; or (ii)
a partnership that is not a Canadian partnership for the purposes of the Tax
Act.
  "NPI Agreements" means the net
profits interest agreements between Penn West and certain of Penn West's
Operating Entities.
  "NPIs" means the net profits
interests granted to Penn West under the NPI Agreements.
  "NYSE" means the New York Stock
Exchange.
  "Operating Entities" means,
collectively, PWPL, Penn West Partnership, Canetic ABC Limited Partnership,
Titan Canada Resources, Canetic Resources Partnership, Petrofund Ventures Trust
and Upton Resources Inc., each a direct or indirect wholly-owned subsidiary of
Penn West as at the date hereof, and "Operating Subsidiary" means
any one of them, as applicable.
  "Operating Entities Securities"
means the Internal Notes, the NPIs, the common shares of PWPL and any other
securities of the Operating Entities owned, directly or indirectly, by Penn
West.
  "Penn West", "we", "us","our" or"Trust"means Penn West Energy
Trust, a trust established under the laws of the Province of Alberta pursuant to
the Trust Indenture.  Where the context requires, these terms also
include all of Penn West's Subsidiaries on a consolidated basis.
  "Penn West Partnership"means Penn West
Petroleum, a general partnership, the partners of which as at the date hereof
are PWPL, Trocana Resources Inc. and Canetic Saskatchewan Trust.
  "Petrofund" means Petrofund
Energy Trust, a trust established under the laws of the Province of
Ontario.
  "Petrofund Acquisition" means
the plan of arrangement under the ABCA pursuant to which Penn West acquired
Petrofund on June 30, 2006.
  "PWPL" means Penn West
Petroleum Ltd., a corporation amalgamated under the ABCA, a wholly-owned
subsidiary of Penn West and the administrator of Penn West pursuant to the
Administration Agreement.
  "SEC" means the United States
Securities and Exchange Commission.
  "Sproule" means Sproule
Associates Limited, independent petroleum consultants of Calgary,
Alberta.
  "Sproule Report" means the
report prepared by Sproule dated February 26, 2009 evaluating approximately 32%
and auditing approximately 8% of the crude oil, natural gas and natural gas
liquids reserves and the net present value of future net revenue attributable to
those reserves effective as at December 31, 2008.
  "Subsidiaries" has the meaning
ascribed thereto in the Securities Act (Ontario) and,
for greater certainty, includes all corporations, partnerships and trusts owned,
controlled or directed, directly or indirectly, by Penn West.
  "Tax Act" means the Income Tax Act(Canada),
R.S.C. 1985, C. 1 (5th Supp.), as amended, including the regulations promulgated
thereunder, as amended from time to time.
  "Trust Indenture" means the
trust indenture between the Trustee and PWPL, as amended and restated as of
June 30, 2006 and as subsequently amended on November 29,
2007.
  "Trust Unit" means a trust unit
issued by us, each trust unit representing an equal undivided beneficial
interest in our assets.
  "Trustee" means CIBC Mellon
Trust Company, our trustee.
  5
  "TSX" means the Toronto Stock
Exchange.
  "United States" or "U.S." means the United States
of America.
  "Unitholders" means holders of
Penn West Trust Units.
  "undeveloped land" and "unproved property" each mean a
property or part of a property to which no reserves have been specifically
attributed.
  "U.S. GAAP" means United States
generally accepted accounting principles.
  "Vault" means Vault Energy
Trust, a trust established under the laws of the Province of
Alberta.
  "Vault Acquisition" means the
plan of arrangement under the ABCA pursuant to which Penn West acquired Vault on
January 10, 2008.
  CONVENTIONS
  Certain
terms used herein are defined in the "Glossary of Terms".  Certain
other terms used herein but not defined herein are defined in NI 51-101
and, unless the context otherwise requires, shall have the same meanings herein
as in NI 51-101.  A discussion of the principal differences
between Penn West's financial results calculated under Canadian GAAP and under
U.S. GAAP is included in the Form 40-F.  On March 26, 2009, the
exchange rate for U.S. dollars, expressed in Canadian dollars, based on the noon
rate as reported by the Bank of Canada, was Cdn$1.00 equals
US$0.8110.
  All
dollar amounts in this document are expressed in Canadian dollars, except where
otherwise indicated. References to "$" or "Cdn$" are to Canadian dollars,
references to "US$" are
to United States dollars and references to "£" are to pounds
sterling.
 
 All
financial information herein has been presented in Canadian dollars in
accordance with Canadian GAAP, which differs from U.S. GAAP.
  ABBREVIATIONS
  Oil and Natural Gas
      Liquids
              Natural
      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
      metresMMbtu
              
              million
      British Thermal Units
   6
  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
      one million dollars.MW
              means
      megawatt.MWh
              means
      megawatt hour.CO2
              means
      carbon dioxide.
 
  OIL
AND GAS INFORMATION ADVISORIES
  Where
any disclosure of reserves data is made in this Annual Information Form
(including the Appendices hereto) that does not reflect all of the reserves of
Penn West, the reader should note that the estimates of reserves and future net
revenue for individual properties may not reflect the same confidence level as
estimates of reserves and future net revenue for all properties, due to the
effects of aggregation.
  All
production and reserves quantities included in this Annual Information Form
(including the Appendices hereto) have been prepared in accordance with Canadian
practices and specifically in accordance with NI 51-101.  These
practices are different from the practices used to report production and to
estimate reserves in reports and other materials filed with the SEC by companies
in the United States.  See "Risk Factors - Canadian and United States
practices differ in reporting reserves and production and our estimates may not
be comparable to those of companies in the United States" for a summary of such
differences.  Nevertheless, as part of the Form 40-F, Penn West has
disclosed proved reserves quantities using the standards contained in SEC
Regulation S-X, and the standardized measure of discounted future net cash flows
relating to proved oil and gas reserves determined in accordance with Statement
No. 69 of the U.S. Financial Accounting Standards Board, "Disclosures About Oil
and Gas Producing Activities", which disclosure complies with the SEC's rules
for disclosing oil and gas reserves.
  References
in this Annual Information Form to undeveloped land and unproved properties
held, owned or acquired by us, or in respect of which we have an interest, refer
to undeveloped land or unproved properties in respect of which we have a lease
or other contractual right to explore for, develop and exploit hydrocarbons
underlying such undeveloped land or unproved properties.
   7
  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
              
              0.950MMbtu
      (at standard)
              gigajoules
              
              1.053gigajoules
      (at standard)
              Mcf
              
              1.055
  8
  SPECIAL NOTE REGARDING FORWARD-LOOKING
STATEMENTS
  In the
interest of providing Unitholders and potential investors with information
regarding Penn West, including management's assessment of Penn West's future
plans and operations, certain statements contained and incorporated by reference
in this document constitute forward-looking statements or information
(collectively "forward-looking
statements") within the meaning of the "safe harbour" provisions of
applicable securities legislation.  Forward-looking statements are
typically identified by words such as "anticipate", "continue", "estimate",
"expect", "forecast", "may", "will", "project", "could", "plan", "intend",
"should", "believe", "outlook", "potential", "target" and similar words
suggesting future events or future performance.  In addition,
statements relating to "reserves" or "resources" are deemed to be
forward-looking statements as they involve the implied assessment, based on
certain estimates and assumptions, that the reserves and resources described
exist in the quantities predicted or estimated and can be profitably produced in
the future.  In particular, this document and the documents
incorporated by reference herein contain, without limitation, forward-looking
statements pertaining to the following: the performance characteristics of our
oil and natural gas properties; the potential impact on our business, business
strategies and plans, business model, future growth prospects, distribution
policies and Unitholders of the SIFT Tax (as defined herein) and the different
actions that we might take in response to the SIFT Tax and the potential impact
those actions could have on us and our Unitholders, including without
limitation, our potential ability to shield our taxable income from income tax
using our tax pools for a period of time following the implementation of the
SIFT Tax and the impact this would have on our distributions and Unitholders;
the impact that the new Alberta royalty framework may have on us, including on
our business strategies and plans; our environmental regulation compliance costs
and strategies, the sufficiency of our environmental program and our ability to
fund our asset retirement obligations; oil and natural gas production level
estimates; our 2009 capital expenditure levels, the timing of making said
expenditures, the key elements of our 2009 capital expenditure program and the
method of funding said expenditures; our business strategies; our exploration
and development plans for our oil and natural gas properties in 2009 and beyond;
matters relating to the proposed acquisition of Reece Energy Exploration Corp.,
including the acquisition metrics, the anticipated benefits of the acquisition
and the anticipated impact of the acquisition on our 2009 capital program;
funding sources for distributions and distribution levels; the quantity and
recoverability of our oil and natural gas reserves and resources; currency
exchange rates, inflation rates and interest rates; the nature and effectiveness
of our risk management strategies; our outlook for oil and natural gas prices;
and our intention and ability to maintain a balanced portfolio of liquids and
natural gas production and the benefits we may derive therefrom.
  With
respect to forward-looking statements contained or incorporated by
referencein this
document, we have made assumptions regarding, among other things: future capital
expenditure levels; future oil and natural gas prices and differentials between
light, medium and heavy oil prices; future oil and natural gas production
levels; future exchange rates and interest rates; the amount of future cash
distributions that we intend to pay; the cost of expanding our property
holdings; our ability to obtain equipment in a timely manner to carry out
development activities; our ability to market our oil and natural gas
successfully to current and new customers; the impact of increasing competition;
our ability to obtain financing on acceptable terms; and our ability to add
production and reserves through our development and exploitation
activities.  In addition, many of the forward-looking statements
contained in this document are located proximate to assumptions that are
specific to those forward-looking statements, and such assumptions should be
taken into account when reading such forward-looking statements.
  Although
Penn West believes that the expectations reflected in the forward-looking
statements contained or incorporated by reference in this document, and the
assumptions on which such forward-looking statements are made, are reasonable,
there can be no assurance that such expectations will prove to be
correct.  Readers are cautioned not to place undue reliance on
forward-looking statements included or incorporated by reference in this
document, as there can be no assurance that the plans, intentions or
expectations upon which the forward-looking statements are based will
occur.  By their nature, forward-looking statements involve numerous
assumptions, known and unknown risks and uncertainties that contribute to the
possibility that the predictions, forecasts, projections and other
forward-looking statements will not occur, which may cause Penn West's actual
performance and financial results in future periods to differ materially from
any estimates or projections of future performance or results expressed or
implied by such forward-looking statements.  These risks and
uncertainties include, among other things: the impact of weather conditions on
seasonal demand and our ability to execute capital programs; risks inherent in
oil and natural gas operations; uncertainties associated with estimating
reserves and resources; competition for, among other things, capital,
acquisitions of reserves, resources, undeveloped lands and skilled personnel;
incorrect assessments of the value of acquisitions; geological, technical,
drilling and processing problems; general economic conditions in Canada, the
U.S. and globally, and in particular, the ongoing global financial crisis and
its impacts on commodity prices and our access to capital; industry conditions,
including fluctuations in the price of oil and natural gas;
   9
  royalties
payable in respect of our oil and natural gas production and changes thereto;
changes in government regulation of the oil and natural gas industry, including
environmental regulation; fluctuations in foreign exchange or interest rates;
unanticipated operating events that can reduce production or cause production to
be shut-in or delayed; failure to obtain industry partner and other third-party
consents and approvals when required; stock market volatility and market
valuations; OPEC's ability to control production and balance global supply and
demand of crude oil at desired price levels; political uncertainty, including
the risks of hostilities, in the petroleum producing regions of the world; the
need to obtain required approvals from regulatory authorities from time to time;
failure to realize the anticipated benefits of acquisitions, including the
completed and proposed acquisitions discussed herein; changes in taxation laws
and regulations that affect us and our securityholders; changes in the Alberta
royalty framework and their impact on us; uncertainty of obtaining required
approvals in respect of acquisitions and mergers; and the other factors
described under "Risk Factors" in this document and in Penn West's public
filings available in Canada at www.sedar.com and in the United States at
www.sec.gov.  Readers are cautioned that this list of risk factors
should not be construed as exhaustive.
  The
forward-looking statements contained and incorporated by reference in this
document speak only as of the date of this document. Except as expressly
required by applicable securities laws, Penn West does not undertake any
obligation to publicly update or revise any forward-looking statements, whether
as a result of new information, future events or otherwise. The forward-looking
statements contained and incorporated by reference in this document are
expressly qualified by this cautionary statement.
  NON-GAAP MEASURES
  This
Annual Information Form includes measures not defined under generally accepted
accounting principles ("GAAP"), including funds flow and
netback.  Non-GAAP measures do not have any standardized meaning
prescribed by GAAP and are therefore unlikely to be comparable to similar
measures presented by other issuers.  Funds flow is cash flow from
operating activities before changes in non-cash working capital and asset
retirement expenditures.  Funds flow is used to assess our ability to
fund distributions and planned capital programs.  Netback is a
per-unit-of-production measure of operating margin used in capital allocation
decisions.  For more information, see Penn West's management's
discussion and analysis for the year ended December 31, 2008 (available on
SEDAR at www.sedar.com and on EDGAR at www.sec.gov), which includes a
reconciliation of "funds flow" to cash flow from operating activities and sets
out the method that we use to calculate our netbacks.
  EFFECTIVE DATE OF
INFORMATION
  Except
where otherwise indicated, the information in this Annual Information Form is
presented as at the end of Penn West's most recently completed financial year,
being December 31, 2008.
   10
  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.
   11
  
 Notes:
  (1)
              The
      Unitholders own 100 percent of Penn West's
  equity.
 (2)
              Cash
      distributions are made on a monthly basis to Unitholders based upon, among
      other things, our funds flow.  Our primary sources of funds flow
      are payments from PWPL and our other Operating Entities pursuant to the
      NPIs and interest on the principal amount of the Internal
      Notes.
 (3)
              PWPL
      was formed effective as of January 1, 2009 pursuant to the amalgamation of
      Penn West Petroleum Ltd., Endev Energy Inc., 990009 Alberta Inc., 1075264
      Alberta Ltd. and 1167639 Alberta
Ltd.
 (4)
              As
      at the date hereof, PWPL, Trocana Resources Inc. 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, 2008, other than PWPL and the
      Penn West Partnership, Penn West does not have any subsidiaries: (i) the
      total assets of which exceed 10% of Penn West's consolidated assets (or
      20% of Penn West's consolidated assets when aggregated with all other
      subsidiaries of Penn West other than PWPL and the Penn West Partnership);
      or (ii) the sales and operating revenues of which exceed 10% of Penn
      West's consolidated sales and operating revenues (or 20% of Penn West's
      consolidated sales and operating revenues when aggregated with all other
      subsidiaries of Penn West other than PWPL and the Penn West
      Partnership).
   12
  GENERAL DEVELOPMENT OF THE
BUSINESS
  History
and Development
  Year
Ended December 31, 2006
  NYSE
Listing
  On June
22, 2006, the Trust Units were listed on the NYSE.
  Petrofund
Acquisition
  Effective
June 30, 2006, Penn West completed the Petrofund Acquisition, pursuant to
which Penn West acquired Petrofund on the basis of an exchange of 0.60 of a
Trust Unit for each one (1) trust unit of Petrofund.  An aggregate of
approximately 70.7 million Trust Units were issued.  A special cash
distribution in the amount of $1.10 per trust unit of Petrofund, of which $0.10
per unit was to align the distribution record dates of the trusts, was made
immediately prior to the completion of the Petrofund Acquisition to the holders
of trust units of Petrofund.  An aggregate of $130 million was
distributed.  As a result of the Petrofund Acquisition, Penn West
acquired 71 MMbbl of light/medium crude oil and NGLs, 1 MMbbl of heavy
oil and 279 Bcf of natural gas on a proved reserve basis, 94 MMbbl of
light/medium crude oil and NGLs, 1 MMbbl of heavy oil and 371 Bcf of
natural gas on a proved plus probable reserve basis, and 352,600 net acres
of undeveloped land.  Penn West also assumed $610 million of bank
indebtedness of Petrofund in connection with the Petrofund
Acquisition.
  Other
Acquisitions and Dispositions
  We
completed property acquisitions, net of dispositions, of $6 million in
2006.  Other than the Petrofund Acquisition described above, we did
not complete any corporate acquisitions in 2006.
  Changes to Taxation of Income
Trusts
  On
October 31, 2006, the Federal Minister of Finance proposed to deny the deduction
of distributions at the trust level and subject any income of certain publicly
traded mutual fund trusts to tax at rates comparable to the combined federal and
provincial corporate tax and to treat such distributions as taxable dividends to
the unitholders (the "SIFT
Tax").  On December 21, 2006, the Federal Minister of Finance
released draft legislation to implement the SIFT Tax pursuant to which,
commencing January 1, 2011 (provided we only experience "normal growth" and no
"undue expansion" before then) certain distributions from us which would have
otherwise been taxed as ordinary income generally will be characterized as
dividends to our Unitholders and will be subject to tax at the corporate rates
at the trust level.  On June 22, 2007, the legislation received Royal
assent.
  The Trust
is a taxable entity under the Tax Act and is taxable only on income that is not
distributed or distributable to the Unitholders.  As the Trust
distributes all of its taxable income to the Unitholders pursuant to the Trust
Indenture and currently satisfies the requirements of the Tax Act applicable to
the Trust, the Trust does not expect to pay income taxes until the earlier of
January 1, 2011 or if and when it ceases to be a trust.  The SIFT Tax
will not impose a tax on distributions from entities, such as the Trust, until
January 1, 2011 as long as the Trust experiences only "normal growth" as set out
in the guidelines described below.  Commencing in January 2011, the
Trust will be liable for tax on all distributions of income paid or payable to
Unitholders, which distributions the Trust will no longer be able to deduct in
computing its taxable income.  The Trust currently has significant tax
pools and expects to continue to increase its tax pool base until
2011.  Accordingly, it is expected that the Trust will be able to
shelter income for a period of time after the application of the SIFT
Tax.
  The SIFT
Tax provides that, while there is no intention to prevent "normal growth" during
the transitional period, any "undue expansion" would result in the transition
period being terminated with the loss of the benefit to us of that transitional
period.  As a result, the adverse tax consequences resulting from the
SIFT Tax could be borne sooner than January 1, 2011.  On December 15,
2006, the Department of Finance issued guidelines with respect to what is meant
by "normal growth" in this context.  Specifically, the Department of
Finance stated that "normal growth" would include equity growth within certain
"safe harbour" limits, measured by reference to a specified investment
flow-through's (a "SIFT") market capitalization
as of the end of trading on October 31, 2006 (which would include only the
market value of the SIFT's issued and outstanding
   13
  publicly-traded
trust units, and not any convertible debt, options or other interests
convertible into or exchangeable for trust units).  Those safe harbour
limits were 40% for the period from November 1, 2006 to December 31, 2007,
and 20% each for calendar year 2008, 2009 and 2010.  Moreover, these
limits were cumulative, so that any unused limit for a period carries over into
the subsequent period.  Additional details of the Department of
Finance's guidelines include the following: (i) new equity for these purposes
includes units and debt that is convertible into units (and may include other
substitutes for equity if attempts are made to develop those); and (ii)
replacing debt that was outstanding as of October 31, 2006 with new equity,
whether by a conversion into trust units of convertible debentures or otherwise,
will not be considered growth for these purposes and will therefore not affect
the safe harbour.
  On
December 4, 2008, the Federal Minister of Finance announced changes to the
guidelines discussed above to allow a SIFT to accelerate the utilization of the
SIFT annual safe harbour amount for each of 2009 and 2010 so that the safe
harbour amounts for 2009 and 2010 are available on and after December 4,
2008.  This change does not alter the maximum permitted expansion
threshold for a SIFT, but it allows a SIFT to use its normal growth room
remaining as of December 4, 2008 in a single year, rather than staging a portion
of the normal growth room over the 2009 and 2010 years.  The
Department of Finance has indicated that the issuance of trust units by a SIFT
as consideration in connection with the acquisition of, or the merger with,
another SIFT, will not be considered growth for these purposes and will
therefore not affect a SIFT's safe harbour.  Therefore, our issuance
of Trust Units in connection with the acquisition of Canetic and Vault is not
considered growth for these purposes and did not affect our safe
harbour.  The Department of Finance has also indicated that a SIFT's
market capitalization for the purpose of calculating a SIFT's "safe harbour"
equity growth limit is equal to the aggregate market capitalization of the SIFT
and all SIFTs acquired by such SIFT as of the end of trading on October 31,
2006.  The combined market capitalization of the Trust, Canetic and
Vault as of the close of trading on October 31, 2006, having regard only to the
issued and outstanding publicly-traded Trust Units and Canetic and Vault trust
units at such date, was approximately $15 billion.  We believe that,
as at March 26, 2009, our remaining combined "safe harbour" equity growth amount
for the period ending December 31, 2010 is approximately $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% in 2011 and 15% in
2012) plus the provincial SIFT tax rate discussed below.  Pursuant to
proposed regulations to the Tax Act, the provincial SIFT Tax rate will be based
on the general provincial corporate income tax rate in each province in which
the Trust has a permanent establishment.  For purposes of calculating
this component of the tax, the general corporate taxable provincial allocation
formula will be used.  Specifically, the Trust's taxable
distributions, if any, will be allocated to provinces by taking half of the
aggregate of: (i) that proportion of the Trust's taxable distributions, if any,
for the year that the Trust's wages and salaries in the province are of its
total wages and salaries in Canada; and (ii) that proportion of the Trust's
taxable distributions, if any, for the year that the Trust's gross revenues in
the province are of its total gross revenues in Canada.  It is
anticipated that the Trust would be considered to have a permanent establishment
in Alberta only, where the provincial tax rate in 2011 is expected to be 10%,
which will result in an effective tax rate of 26.5% in 2011.  Taxable
distributions, if any, that are not allocated to any province, would instead be
subject to a 10% rate constituting the provincial component.
  On July
14, 2008, the Federal Minister of Finance announced proposed amendments to the
Tax Act, including technical amendments to clarify certain aspects of the SIFT
Tax and to provide rules to facilitate the conversion of existing SIFTs into
corporations on a tax-deferred basis (the "Conversion
Rules").  The Conversion Rules address many of the principal
substantive and administrative issues that arise when structuring a corporate
conversion of an income trust under the Tax Act. The Conversion Rules
contemplate two alternatives for the conversion of a publicly-traded SIFT into a
taxable Canadian corporation and the winding-up of the SIFT's underlying
structure.  The first alternative involves the winding-up of the SIFT
into a taxable Canadian corporation whereas the second approach involves the
distribution by the publicly-traded SIFT of shares of an underlying taxable
Canadian corporation to its unitholders.  The Conversion
Rules will generally only apply to the winding-up of a SIFT or a
distribution of shares completed after July 14, 2008 and before 2013. Bill
C-10, which received Royal Assent on March 12, 2009, contained legislation
implementing the Conversion Rules.
  As a
result of the enactment of the SIFT Tax in 2007, the future income taxes
disclosed in our financial statements were adjusted to include temporary
differences between the accounting and tax bases of our assets and liabilities
at the trust level, as further described in Note 9 to our audited consolidated
financial statements for the year ended December 31, 2008. In addition, the
reported estimated net present value of future net revenues from our oil and
natural gas reserves on an "after-tax" basis now reflects the impact of the SIFT
Tax. We continue to evaluate alternatives to determine the optimal structure for
our Unitholders beyond 2010.  We are currently hesitant to make
structural changes prior to the end of 2010 unless
   14
  opportunities
arise, as we believe the exemption period has value for our Unitholders. Unless
circumstances change within the current capital markets or the regulatory, tax
or political environment, we currently believe that we will most likely convert
into a dividend paying corporation. However, we are keeping our options open at
this time and cannot provide any assurances in this regard. We do not expect
that a conversion to a corporation would have a major impact on our underlying
operating strategy or business affairs, but cannot provide any assurances in
this regard. We expect that such a conversion could be achieved without creating
a taxable event for most of our Unitholders, particularly if a conversion were
completed prior to January 1, 2013.  However, going forward, the tax
treatment of our distributions or dividends might be different for our
Unitholders or shareholders, as the case may be, depending on the Unitholder's
tax jurisdiction and whether the Unitholder holds its investment in a taxable
account or tax-deferred account.  For additional information on the
SIFT Tax, including its potential impact on us and our Unitholders and the
actions that we might take in response to the SIFT Tax (including with respect
to our anticipated tax horizon), see the following:  "Risk Factors" in
this Annual Information Form; "Other Oil and Gas Information – Tax Horizon" in
Appendix A-3 to this Annual Information Form; and "Enactment of the Tax on
Income Trusts" set forth in our management's discussion and analysis for the
year ended December 31, 2008 (available on SEDAR at www.sedar.com and on
EDGAR at www.sec.gov), which disclosure is incorporated herein by
reference.
  Year
Ended December 31, 2007
  April
2007 Asset Acquisition
  On
April 11, 2007, Penn West completed the acquisition (the "April 2007 Asset Acquisition")
of certain conventional oil and natural gas assets located primarily in the
Province of Alberta, for cash consideration of approximately $329
million.  As a result of the acquisition, Penn West acquired 6 MMbbl
of light/medium crude oil and NGLs, 0.1 MMbbl of heavy oil and 16 Bcf of natural
gas on a proved reserve basis, 8 MMbbl of light/medium crude oil and NGLs, 0.1
MMbbl of heavy oil and 22 Bcf of natural gas on a proved plus probable reserve
basis, and 190,000 net acres of undeveloped land.  The acquisition was
financed using Penn West's existing syndicated credit facility and a new $250
million unsecured, demand credit facility.
  Other
Acquisitions and Dispositions
  In
addition to the April 2007 Asset Acquisition described above, we completed
property acquisitions, net of dispositions, of $93 million in
2007.  We also completed one corporate acquisition for total cash
consideration of $21 million resulting in total acquisitions, net of
dispositions, of $443 million in 2007 (including the April 2007 Asset
Acquisition).
  Private
Placement of 2007 Senior Notes
  Effective
May 31, 2007, PWPL completed the private placement of an aggregate of
US$475 million principal amount of notes (the "2007 Senior
Notes").  The private placement consisted of the issuance of
US$160 million principal amount of 5.68 percent notes due in 2015, US$155
million principal amount of 5.80 percent notes due in 2017, US$140 million
principal amount of 5.90 percent notes due in 2019 and US$20 million principal
amount of 6.05 percent notes due in 2022.  The 2007 Senior Notes are
unsecured and rank equally with Penn West's bank credit
facilities.  The proceeds of the 2007 Senior Notes were used to repay
a portion of the indebtedness under Penn West's bank credit
facilities.
  Year
Ended December 31, 2008
  Vault
Acquisition
  Effective
January 10, 2008, Penn West completed the Vault Acquisition, pursuant to
which Penn West acquired Vault on the basis of an exchange of 0.14 of a Trust
Unit for each one trust unit of Vault, 0.14 of a Trust Unit for each one trust
unit of Vault into which the Series A exchangeable shares of Vault Energy
Inc. were exchangeable, and a payment of $0.51 for each one warrant to purchase
a trust unit of Vault.  An aggregate of approximately 5.6 million
Trust Units were issued and an aggregate of approximately $768,111 was
paid.  As a result of the Vault Acquisition, Penn West acquired 7
MMbbl of light/medium crude oil and NGLs and 56 Bcf of natural gas on a proved
reserve basis, and 10 MMbbl of light/medium crude oil and NGLs and 74 Bcf of
natural gas on a proved plus probable reserve basis.  Penn West also
acquired 125,000 net acres of undeveloped land.
   15
  In
connection with the Vault Acquisition, Penn West also assumed approximately $89
million of bank indebtedness of Vault, $50 million principal amount of 7.2%
Debentures issued by Vault and $49 million principal amount of 8% 2005
Debentures issued by Vault.  On March 5, 2008, Penn West repurchased
for cancellation $24 million principal amount of the 7.2% Debentures and $11,000
principal amount of the 8% 2005 Debentures pursuant to issuer bids required by
the 7.2% Debenture Indenture and the 8% 2005 Debenture Indenture,
respectively.
  Canetic
Acquisition
  Effective
January 11, 2008, Penn West completed the Canetic Acquisition, pursuant to
which Penn West acquired Canetic on the basis of an exchange of 0.515 of a Trust
Unit for each one trust unit of Canetic.  An aggregate of
approximately 124.3 million Trust Units were issued.  In
addition, a special cash distribution in the amount of $0.09 per trust unit of
Canetic was made to holders of trust units of Canetic of record at the close of
business on January 10, 2008.  An aggregate of approximately $22
million was distributed to Canetic unitholders on January 15,
2008.  As a result of the Canetic Acquisition, Penn West acquired
approximately 89 MMbbl of light/medium crude oil and NGLs, 13 MMbbl of heavy oil
and 408 Bcf of natural gas on a proved reserve basis and 120 MMbbl of
light/medium crude oil and NGLs, 17 MMbbl of heavy oil and 564 Bcf of natural
gas on a proved plus probable reserve basis.  Penn West also acquired
774,000 net acres of undeveloped land.
  In
connection with the Canetic Acquisition, Penn West assumed approximately $1.4
billion of bank indebtedness of Canetic, $18 million principal amount of 6.5%
2005 Debentures issued by Canetic, $229 million principal amount of 6.5% 2006
Debentures issued by Canetic, $8 million principal amount of 8% 2004 Debentures
issued by Canetic and $6 million principal amount of 9.4% convertible unsecured
subordinated debentures issued by Canetic (which were subsequently repaid on
July 31, 2008 when they matured and are no longer outstanding).
  Concurrent
with the closing of the Canetic Acquisition, Penn West secured a $4 billion
credit facility for a three-year term with a syndicate of 18 Canadian and
international banks.  The new credit facility was initially used to
retire Penn West's indebtedness under its then existing bank credit facilities
and to retire all bank indebtedness assumed by Penn West in connection with the
Vault Acquisition and the Canetic Acquisition.
  Endev Acquisition
  Effective
July 22, 2008, Penn West completed the Endev Acquisition, pursuant to which Penn
West acquired Endev on the basis of an exchange of 0.041 of a Trust Unit for
each one (1) common share of Endev.  An aggregate of approximately 3.6
million Trust Units were issued.  As a result of the Endev
Acquisition, Penn West acquired approximately 1,242 Mbbl of light/medium crude
oil and NGLs, 56 Mbbl of heavy oil and 28,021 MMcf of natural gas on a proved
reserve basis, 1,900 Mbbl of light/medium crude oil and NGLs, 81 Mbbl
of heavy oil and 40,760 MMcf of natural gas on a proved plus probable reserve
basis, and 98,580 net acres of undeveloped land.  Penn West also
assumed $45 million of debt and working capital in connection with the
Endev Acquisition.
  Other
Acquisitions and Dispositions
  We
completed property dispositions, net of acquisitions, of $50million in
2008.
  Private
Placement of 2008 Senior Notes
  Effective
May 29, 2008, PWPL completed the private placement of an aggregate of US$480
million and Cdn$30 million principal amount of senior guaranteed unsecured notes
(the "2008 Senior
Notes"). The private placement consisted of the issuance of US$153
million principal amount of 6.12 percent notes due in 2016, US$278 million
principal amount of 6.30 percent notes due in 2018, Cdn$30 million principal
amount of 6.16 percent notes due in  2018 and US$49 million principal
amount of 6.40 percent notes due in 2020. The 2008 Senior Notes are unsecured
and rank equally with PWPL's bank credit facilities and the 2007 Senior Notes.
The proceeds of the private placement of the 2008 Senior Notes were used to
repay a portion of the indebtedness outstanding under our bank credit
facilities.
   16
  Private
Placement of 2008 Pounds Sterling Senior Notes
  Effective
July 31, 2008, PWPL completed the private placement of an aggregate of £57
million principal amount of senior guaranteed unsecured notes (the "2008 Pounds Sterling Senior
Notes"). The private placement consisted of the issuance of £57 million
principal amount of 7.78 percent notes due in 2018.  The 2008 Pounds
Sterling Senior Notes are unsecured and rank equally with PWPL's bank credit
facilities, the 2007 Senior Notes and the 2008 Senior Notes. The proceeds of the
private placement of the 2008 Pounds Sterling Senior Notes were used to repay a
portion of the indebtedness outstanding under our bank credit
facilities.
 
 Revisions to Alberta Royalty
Regime
  In
December 2008, the Government of Alberta passed into law a "New Royalty
Framework" which introduces new royalty rates for conventional oil, natural gas
and bitumen effective January 1, 2009 that are sensitive to price and production
levels and will apply to both new and existing oil sands projects and
conventional oil and gas activities. Certain transitional rates and short-term
incentives outside of the New Royalty Framework have also been provided by the
Government of Alberta. In 2008, approximately 55% of our aggregate crude oil and
natural gas production was from Alberta Crown leases. The net reserves volumes
and estimated net present value of future net revenue attributable to our
reserves located in Alberta contained in the reserves reported in Appendix A-3
to this Annual Information Form reflect Alberta's New Royalty Framework. For
additional information, see the following: "Industry Conditions – Provincial
Royalties and Incentives - Alberta" in this Annual Information Form; "Risk
Factors" in this Annual Information Form; and "The New Alberta Royalty
Framework" set forth in our management's discussion and analysis for the year
ended December 31, 2008 (available on SEDAR at www.sedar.com and on
EDGAR at www.sec.gov), which disclosure is incorporated herein by
reference.
 
 Recent
Developments
 
 Public Offering of Trust
Units
 
 On
February 5, 2009, Penn West completed a public offering of 17.7 million Trust
Units at a price of $14.10 per Trust Unit for aggregate gross proceeds of
approximately $250 million.  The offering was underwritten by a
syndicate of underwriters.  The net proceeds of the offering were used
by Penn West to partially fund capital expenditures and to reduce its
indebtedness.  The Trust Units were issued by way of a prospectus
supplement that was filed with securities regulatory authorities in Canada and
the U.S. under Penn West's short form base shelf prospectus dated June 13, 2008,
which was previously filed with securities regulatory authorities across Canada
and in the U.S. under the multi-jurisdictional disclosure system.
  Acquisitions
and Dispositions
  To date,
we have completed property dispositions, net of acquisitions, of approximately
$137million in
2009.
  Reece
Acquisition
  On March
10, 2009, Penn West announced its intention to add to its position in the
Dodsland area of Saskatchewan with the acquisition of Reece Energy Exploration
Corp. ("Reece") for a
purchase price of approximately $92 million.  Penn West will issue
approximately 4.6 million Trust Units and assume approximately $40 million of
debt in connection with the acquisition. The acquisition will add approximately
2,100 boe/d of production, of which approximately 67 percent is light oil, and
approximately 75,000 net acres of undeveloped land, a significant portion of
which is contiguous with our land position in the Dodsland area.  The
acquisition is currently scheduled to close on April 30, 2009, subject to the
satisfaction of various industry standard closing conditions and the receipt of
all necessary regulatory and other third party approvals, including the approval
of Reece's shareholders and the Court of Queen's Bench of Alberta.
  Significant
Acquisitions
  There
were no significant acquisitions completed by Penn West during the financial
year ended December 31, 2008 for which disclosure was required under
Part 8 of National Instrument 51-102, other than the Canetic
Acquisition.  For a description of the Canetic Acquisition, see
"General Development of the Business – History and Development – Year
Ended December 31, 2008 - Canetic Acquisition" above.  Penn West has
filed a Form 51-102F4 – Business Acquisition Report in respect of the
Canetic Acquisition.
   17
  DESCRIPTION OF OUR
BUSINESS
  Overview
  Our
principal undertaking is to issue Trust Units and to acquire and hold securities
of Subsidiaries, net profits interests, royalties, notes and other
interests.  Our direct and indirect Subsidiaries carry on the business
of acquiring, developing, exploiting and holding interests in petroleum and
natural gas properties and assets related thereto.  A portion of the
funds flow from the assets is paid from PWPL and our other Operating Entities to
us by way of interest and principal payments on the Internal Notes and payments
under the NPI Agreements.
  The Board
of Directors may declare distributions payable to the Unitholders and allocate
all or any of our income to the Unitholders.  It is currently
anticipated that the only income we will receive will be from PWPL and our other
Operating Entities by way of interest received on the principal amount of the
Internal Notes and payments pursuant to the NPIs.  We make monthly
cash distributions to Unitholders from this income after any expenses and any
cash redemptions of Trust Units.
  Cash
distributions are made on or about the 15th day of
each month to Unitholders of record on or about the last calendar day of the
immediately preceding month.
  As at
March 26, 2009, we had approximately 1,950employees.
  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.
  Reserves
Data
  See
Appendices A-1, A-2 and A-3 for complete NI 51-101 oil and gas reserves
disclosure for Penn West as at December 31, 2008.
   18
  CAPITALIZATION OF PWPL
  Common
Shares
  PWPL has
authorized for issuance an unlimited number of common shares.  The
Trust owns all of the issued common shares.  The voting of such shares
is delegated to the Board of Directors under the Trust Indenture other
than:  (i) any sale, lease or other disposition of, or any
interest in, all or substantially all of the Trust's assets, except in
conjunction with an internal reorganization of the Trust's direct or indirect
assets as a result of which the Trust has the same, or substantially similar,
interest, whether direct or indirect, in the assets as the interest, whether
direct or indirect, that it had prior to the reorganization; (ii) any
statutory amalgamation of PWPL with any other entity, except in conjunction with
an internal reorganization as referred to in paragraph (i) above; (iii) any
statutory arrangement involving PWPL, except in conjunction with an internal
reorganization as referred to in paragraph (i) above; (iv) any amendment to the
articles of PWPL to increase or decrease the minimum or maximum number of
directors; or (v) any material amendment to the articles of PWPL to change the
authorized share capital or amend the rights, privileges, restrictions and
conditions attaching to any class of PWPL's shares in a manner which may be
prejudicial to Penn West, without the approval of the Unitholders by special
resolution at a meeting of Unitholders called for that purpose.
  The
holders of common shares are entitled to receive notice of and to attend all
meetings of the shareholders of PWPL and to one vote at such
meetings.  The holders of common shares will be, at the discretion of
the Board of Directors and subject to applicable legal restrictions, entitled to
receive any dividends declared by the Board of Directors on the common shares.
The holders of common shares will be entitled to share equally in any
distribution of the assets of PWPL upon the liquidation, dissolution, bankruptcy
or winding-up of PWPL or other distribution of its assets among its shareholders
for the purpose of winding-up its affairs subject to the rights, privileges,
restrictions and conditions attaching to any other shares having priority over
the common shares.
  Preferred
Shares
  PWPL is
authorized to issue an unlimited number of preferred shares in
series.  Before any shares of a particular series are issued, the
Board of Directors shall, by resolution, fix the number of shares that will form
such series and shall, subject to the limitations set out herein, by resolution
fix the designation, rights, privileges, restrictions and conditions to be
attached to the preferred shares of such series.  The preferred shares
of each series shall rank on a parity with the preferred shares of every other
series with respect to accumulated dividends and return of
capital.  The preferred shares are entitled to a preference over the
common shares and over any other shares of PWPL ranking junior to the preferred
shares with respect to the payment of dividends and the distribution of assets
in the event of the liquidation, dissolution or winding-up of PWPL, whether
voluntary or involuntary, or any other distribution of the assets of PWPL among
its shareholders for the purpose of winding-up its affairs.
  The Board
of Directors has authorized one series of preferred shares, being the first
preferred shares series A (the "Series A Preferred
Shares").  One thousand Series A Preferred Shares have
been authorized for issuance.  Holders of Series A Preferred
Shares are entitled to receive preferential cash dividends in such amounts as
may be declared by the Board of Directors.  The payment of such
dividends is in priority to dividends on the common shares of PWPL and all other
shares ranking junior to the Series A Preferred Shares with respect to the
payment of dividends.  PWPL has the right to redeem at any time all,
or from time to time any part, of the then outstanding Series A Preferred
Shares at a price per share equal to $1,000, together with all accrued and
unpaid dividends thereon up to the date fixed for redemption.  Each
registered holder of Series A Preferred Shares is entitled to require PWPL
to retract at any time any Series A Preferred Shares tendered at a price
per share equal to $1,000, together with all accrued and unpaid dividends
thereon up to the retraction date.  In the event of the liquidation,
dissolution or winding-up of PWPL or other distribution of the assets of PWPL
among its shareholders for the purpose of winding-up its affairs, the holders of
Series A Preferred Shares are entitled to receive an amount per
Series A Preferred Share equal to $1,000 per share, together with any
accrued and unpaid dividends to the date of commencement of such event, to be
paid all such money before any money shall be paid or property or assets
distributed to the holders of any common shares of PWPL or other shares in the
capital of PWPL ranking junior to the Series A Preferred Shares with
respect to return of capital.  After payment of the aforementioned
amount, the Series A Preferred Shares shall not be entitled to share in any
further distribution of the property or assets of PWPL.  So long as
any Series A Preferred Shares are outstanding PWPL may not, without the
approval of the holders of the Series A Preferred Shares, take certain
actions unless all dividends which have been declared have been paid or set
apart for payment.  Subject to applicable law, the holders of the
Series A Preferred Shares are not entitled as such to any voting rights or
to receive notice of or to attend any meeting of the
   19
  shareholders
of PWPL or to vote at any such meeting, except for meetings at which holders of
a specified class or series of shares of PWPL are entitled or required to vote
separately as a class or series pursuant to the provisions of the
ABCA.
  As at the
date hereof, no preferred shares are issued and outstanding.
  Borrowing
  We borrow
funds from time to time to finance the purchase of properties, for capital
expenditures or for other financial obligations or expenditures in respect of
properties held by us or for working capital purposes.
  Certain
debt service charges on borrowed funds attributable to our properties will be
deducted in computing income under the NPIs.  Capital expenditures and
any debt repayment will be scheduled to minimize any income tax payable by
PWPL.
  INFORMATION RELATING TO PENN
WEST
  Trust
Units
  An
unlimited number of Trust Units may be issued pursuant to the Trust
Indenture.  The Trust Units represent equal undivided beneficial
interests in Penn West.  All Trust Units share equally in all
distributions made by Penn West and all Trust Units carry equal voting rights at
meetings of Unitholders.  No Unitholder will be liable to pay any
further calls or assessments in respect of the Trust Units.  No
conversion, retraction or pre-emptive rights attach to the Trust
Units.
  As at
March 26, 2009, approximately 408,249,304 million Trust Units were
outstanding, approximately 6,020,546 million Trust Units were reserved for
issuance on conversion of the Convertible Debentures and approximately
37,367,950 million Trust Units were available for future issuance pursuant to
Penn West's trust unit rights incentive plan and employee stock savings plan
(subject to increase in accordance with such plans).
  Special
Voting Units
  The Trust
Indenture also provides for the issuance of special voting units which are
entitled to such number of votes at meetings of Unitholders and any other rights
or limitations prescribed by the Board of Directors when the Board of Directors
authorizes issuing such special voting units.  The Trust Units and the
special voting units vote together as a single class on all
matters.  In the event of Penn West's liquidation, dissolution or
winding-up, the holders of special voting units will not be entitled to receive
any of Penn West's assets available for distribution to
Unitholders.  The holders of special voting units will not be entitled
to receive dividends or other distributions from Penn West.
  Convertible
Debentures
  Penn West
has five series of convertible debentures outstanding: (i) the 8% 2004
Debentures, (ii) the 8% 2005 Debentures, (iii) the 6.5% 2005 Debentures, (iv)
the 7.2% Debentures, and (v) the 6.5% 2006 Debentures.  The 7.2%
Debentures and the 8% 2005 Debentures were assumed by Penn West pursuant to the
Vault Acquisition, which closed on January 10, 2008.  The 6.5% 2005
Debentures, the 6.5% 2006 Debentures and the 8% 2004 Debentures were assumed by
Penn West pursuant to the Canetic Acquisition, which closed on January 11,
2008.  The following is a summary of the material attributes and
characteristics of the Convertible Debentures.
  The 8%
2004 Debentures were originally issued in the aggregate principal amount of $75
million and approximately $7 million principal amount was outstanding at
March 26, 2009.  The 8% 2004 Debentures mature on August 31,
2009.
  The 8%
2005 Debentures were originally issued in the aggregate principal amount of $55
million and approximately $10 million principal amount was outstanding at
March 26, 2009.  The 8% 2005 Debentures mature on June 30,
2010.
  The 6.5%
2005 Debentures were originally issued in the aggregate principal amount of $60
million and approximately $18 million principal amount was outstanding at
March 26, 2009.  The 6.5% 2005 Debentures mature on July 31,
2010.
   20
  The 7.2%
Debentures were originally issued in the aggregate principal amount of $50
million and approximately $26 million principal amount was outstanding at
March 26, 2009.  The 7.2% Debentures mature on May 31,
2011.
  The 6.5%
2006 Debentures were originally issued in the aggregate principal amount of $230
million and $229 million principal amount was outstanding at March 26,
2009.  The 6.5% 2006 Debentures mature on December 31,
2011.
  Terms
of Convertible Debentures
  The 8%
2004 Debentures bear interest from the date of issue at 8% per annum, which is
payable semi-annually in arrears on February 28 and August 31 in each
year.  The 8% 2005 Debentures bear interest from the date of issue at
8% per annum, which is payable semi-annually in arrears on June 30 and December
31 in each year.  The 6.5% 2005 Debentures bear interest from the date
of issue at 6.5% per annum, which is payable semi-annually in arrears on January
31 and July 31 in each year.  The 7.2% Debentures bear interest from
the date of issue at 7.2% per annum, which is payable semi-annually in arrears
on May 31 and November 30 in each year.  The 6.5% 2006 Debentures bear
interest from the date of issue at 6.5% per annum, which is payable
semi-annually in arrears on June 30 and December 31 in each year.
  The
principal amount of the Convertible Debentures is payable in lawful money of
Canada or, at the option of the Trust and subject to applicable regulatory
approval, by payment of Trust Units as further described under "Payment Upon
Redemption or Maturity" and "Redemption and Purchase".  The interest
on the Convertible Debentures is payable in lawful money of Canada and, in the
case of certain of the Convertible Debentures, at the option of the Trust and
subject to applicable regulatory approval, in accordance with the Interest
Obligation as described under "Interest Payment Option".
  The
Convertible Debentures are direct obligations of the Trust and are not secured
by any mortgage, pledge, hypothec or other charge and are subordinated to other
liabilities of the Trust as described under "Subordination".  The
indentures governing the Convertible Debentures do not restrict the Trust from
incurring additional indebtedness for borrowed money or from mortgaging,
pledging or charging its properties to secure any indebtedness.
  Conversion
Privilege
  The 8%
2004 Debentures are convertible at the holder's option into fully paid and
non-assessable Trust Units at any time prior to the close of business on the
earlier of August 31, 2009, and the last business day immediately preceding the
date specified by Penn West for redemption of the 8% 2004 Debentures, at a
conversion price of $30.2136 per Trust Unit, being a conversion rate of
approximately 33.0977 Trust Units for each $1,000 principal amount of 8% 2004
Debentures.
  The 8%
2005 Debentures are convertible at the holder's option into fully paid and
non-assessable Trust Units at any time prior to the close of business on the
earlier of June 30, 2010 and the last business day immediately preceding the
date specified by Penn West for redemption of the 8% 2005 Debentures, at a
conversion price of $82.14 per Trust Unit, being a conversion rate of
approximately 12.1743 Trust Units for each $1,000 principal amount of 8% 2005
Debentures.
  The 6.5%
2005 Debentures are convertible at the holder's option into fully paid and
non-assessable Trust Units at any time prior to the close of business on the
earlier of July 31, 2010 and the last business day immediately preceding the
date specified by Penn West for redemption of the 6.5% 2005 Debentures, at a
conversion price of $36.8155 per Trust Unit, being a conversion rate of
approximately 27.1625 Trust Units for each $1,000 principal amount of 6.5% 2005
Debentures.
  The 7.2%
Debentures are convertible at the holder's option into fully paid and
non-assessable Trust Units at any time prior to the close of business on the
earlier of May 31, 2011 and the last business day immediately preceding the date
specified by Penn West for redemption of the 7.2% Debentures, at a conversion
price of $75.00 per Trust Unit, being a conversion rate of approximately 13.3333
Trust Units for each $1,000 principal amount of 7.2% Debentures.
  The 6.5%
2006 Debentures are convertible at the holder’s option into fully paid and
non-assessable Trust Units at any time prior to the close of business on the
earlier of December 31, 2011, and the last business day immediately preceding
the date specified by Penn West for redemption of the 6.5% 2006 Debentures, at a
conversion price of $51.5534 per Trust Unit, being a conversion rate of
approximately 19.3974 Trust Units for each $1,000 principal amount of 6.5% 2006
Debentures.
   21
  Redemption
and Purchase
  The 8%
2004 Debentures may be redeemed in whole or in part from time to time at the
option of the Trust on not more than 60 days and not less than 40 days prior
notice, at a redemption price of $1,025 per 8% 2004 Debenture before maturity
(each an "8% 2004 Redemption
Price"), plus accrued and unpaid interest thereon, if any.
  Prior to
maturity, debenture holders may cause the Trust to redeem the 8% 2005 Debentures
in whole or in part from time to time, on not more than 60 days and not less
than 30 days prior notice, at a redemption price of $1,050 per 8% 2005 Debenture
before July 1, 2009, and a redemption price of $1,025 per 8% 2005 Debenture on
or after July 1, 2009 and before maturity (each an "8% 2005 Redemption Price"), in
each case, plus accrued and unpaid interest thereon, if any.
  The Trust
may, on not more than 60 days and not less than 30 days prior notice, redeem the
6.5% 2005 Debentures at a redemption price of $1,050 per 6.5% 2005 Debenture on
or before July 31, 2009, and at a price of $1,025 per 6.5% 2005 Debenture after
July 31, 2009 and before July 31, 2010 (each a "6.5% 2005 Redemption Price"),
plus accrued and unpaid interest thereon, if any.
  The 6.5%
2006 Debentures are not redeemable on or before December 31,
2009.  After December 31, 2009 and prior to maturity, the 6.5% 2006
Debentures may be redeemed in whole or in part from time to time at the option
of the Trust on not more than 60 days and not less than 30 days prior notice, at
a redemption price of $1,050 per 6.5% 2006 Debenture after December 31, 2009 and
on or before December 31, 2010 and at a redemption price of $1,025 per 6.5% 2006
Debenture after December 31, 2010 and before maturity (each a "6.5% 2006 Redemption Price")
in each case, plus accrued and unpaid interest thereon, if any.
  The 7.2%
Debentures are not redeemable on or before May 31, 2009.  The Trust
may, on not more than 60 days and not less than 30 days prior notice, redeem the
7.2% Debentures at a redemption price of $1,050 per 7.2% Debenture after May 31,
2009 and on or before May 31, 2010, and a price of $1,025 per 7.2% Debenture
after May 31, 2010 and before May 31, 2011 (each a "7.2% Redemption Price"), plus
accrued and unpaid interest thereon, if any.
  The Trust
has the right to purchase Convertible Debentures in the market, by tender or by
private contract.
  Payment
upon Redemption or Maturity
  On
redemption or at maturity, the Trust will repay the indebtedness represented by
the Convertible Debentures by paying to the Debenture Trustee in lawful money of
Canada an amount equal to the aggregate applicable redemption price of the
outstanding Convertible Debentures which are to be redeemed or the principal
amount of the outstanding Convertible Debentures which have matured together
with accrued and unpaid interest thereon up to but excluding the date of
redemption or maturity, as applicable.  The Trust may, at its option,
and subject to applicable regulatory approval, elect to satisfy its obligation
to pay the applicable redemption price of the Convertible Debentures which are
to be redeemed or the principal amount of the Convertible Debentures which have
matured, as the case may be, by issuing Trust Units to the holders of the
Convertible Debentures.  Any accrued and unpaid interest thereon will
be paid in cash.  The number of Trust Units to be issued will be
determined by dividing the aggregate applicable redemption price of the
outstanding Convertible Debentures which are to be redeemed or the principal
amount of the outstanding Convertible Debentures which have matured, as the case
may be, by 95 percent of the Current Market Price of the Trust Units on the date
fixed for redemption or the maturity date, as the case may be.  The
term "Current Market
Price" is defined in the Convertible Debenture indentures to mean the
weighted average trading price of the Trust Units on the TSX for the 20
consecutive trading days ending on the fifth trading day preceding the date
fixed for redemption or the maturity date, as the case may be.
  Subordination
  The
payment of the principal of, and interest on, the Convertible Debentures is
subordinated in right of payment, as set forth in the Debenture Indentures, to
the prior payment in full of all Senior Indebtedness of the
Trust.  "Senior
Indebtedness" of the Trust is defined in the Debenture Indentures as the
principal of and premium, if any, and interest on and other amounts in respect
of all indebtedness of the Trust (whether outstanding as at the date of the
Debenture Indentures or thereafter incurred) which includes any indebtedness to
trade creditors, other than indebtedness evidenced by the Convertible Debentures
and all other existing and future debentures or other instruments of the Trust
which, by the terms of the instrument creating or
   22
  evidencing
the indebtedness, is expressed to be pari passu with, or
subordinate in right of payment to, the Convertible Debentures.
  The
Debenture Indentures provide that in the event of any insolvency or bankruptcy
proceedings, or any receivership, liquidation, reorganization or other similar
proceedings relative to the Trust, or to its property or assets, or in the event
of any proceedings for voluntary liquidation, dissolution or other winding-up of
the Trust, whether or not involving insolvency or bankruptcy, or any marshalling
of the assets and liabilities of the Trust, then those holders of Senior
Indebtedness, including any indebtedness to trade creditors, will receive
payment in full before the holders of Convertible Debentures will be entitled to
receive any payment or distribution of any kind or character, whether in cash,
property or securities, which may be payable or deliverable in any such event in
respect of any of the Convertible Debentures or any unpaid interest accrued
thereon.  The Debenture Indentures also provide that the Trust will
not make any payment, and the holders of the Convertible Debentures will not be
entitled to demand, institute proceedings for the collection of, or receive any
payment or benefit (including, without any limitation, by set-off, combination
of accounts or realization of security or otherwise in any manner whatsoever) on
account of indebtedness represented by the Convertible Debentures (a) in a
manner inconsistent with the terms (as they exist on the date of issue) of the
Convertible Debentures or (b) at any time when an event of default has occurred
under the Senior Indebtedness and is continuing and the notice of such event of
default has been given by or on behalf of the holders of Senior Indebtedness to
the Trust, unless the Senior Indebtedness has been repaid in full.
  The
Convertible Debentures are effectively subordinate to claims of creditors of the
Trust's Subsidiaries except to the extent the Trust is a creditor of such
Subsidiaries ranking at least pari passu with such other
creditors.  Specifically, the Convertible Debentures are subordinated
in right of payment to the prior payment in full of all indebtedness under the
Trust's credit facilities and to the prior payment in full of PWPL's 2007 Senior
Notes, 2008 Senior Notes and 2008 Pounds Sterling Senior Notes.
  Priority
over Trust Distributions
  The
Debenture Indentures provide that certain expenses of the Trust must be deducted
in calculating the amount to be distributed to the
Unitholders.  Accordingly, the funds required to satisfy the interest
payable on the Convertible Debentures, as well as the amount payable upon
redemption or maturity of the Convertible Debentures or upon an Event of Default
(as defined below), will be deducted and withheld from the amounts that would
otherwise be payable as distributions to Unitholders.
  Change
of Control of the Trust
  Within 30
days following the occurrence of a change of control of the Trust involving the
acquisition of voting control or direction over 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 the remaining
Convertible Debentures of that series, at the applicable Debenture Offer
Price.
  Interest
Payment Option
  The Trust
may elect, from time to time, to satisfy its obligation to pay all or any part
of the interest on the 6.5% 2006 Debentures, the 8% 2004 Debentures and the 6.5%
2005 Debentures (but, for greater certainty, not the 7.2% Debentures or the 8%
2005 Debentures) (the "Interest
Obligation"), on the date it is payable under the applicable Debenture
Indenture (an "Interest Payment
Date"), by delivering sufficient Trust Units to the Debenture Trustee to
satisfy all or the part, as the case may be, of the Interest Obligation in
accordance with the applicable Debenture Indenture (the "Unit Interest Payment
Election").  The Debenture Indentures provide that, upon such
election, the Debenture Trustee shall: (a) accept delivery from the Trust
of Trust Units; (b) accept bids with respect to, and consummate sales of,
such Trust Units, each as the Trust shall direct in its absolute discretion;
(c) invest the proceeds of such sales in short-term permitted government
securities (as defined in the applicable Debenture Indenture) which mature prior
to the applicable Interest Payment Date, and use the
   23
  proceeds
received from such permitted government securities, together with any proceeds
from the sale of Trust Units not invested as aforesaid, to satisfy the Interest
Obligation; and (d) perform any other action necessarily incidental
thereto.
  If a Unit
Interest Payment Election is made, the sole right of a holder of Convertible
Debentures in respect of interest will be to receive cash from the Debenture
Trustee out of the proceeds of the sale of Trust Units (plus any amount received
by the Debenture Trustee from the Trust attributable to any fractional Trust
Units) in full satisfaction of the Interest Obligation, and the holder of such
Convertible Debentures will have no further recourse to the Trust in respect of
the Interest Obligation.
  Events
of Default
  The
Debenture Indentures provide that an event of default ("Event of Default") in respect
of the Convertible Debentures will occur if any one or more of the following
described events has occurred and is continuing with respect of the Convertible
Debentures: (a) failure for 10 days to pay interest on the Convertible
Debentures when due; (b) failure to pay principal or premium, if any, on
the Convertible Debentures when due, whether at maturity, upon redemption, by
declaration or otherwise; (c) certain events of bankruptcy, insolvency or
reorganization of the Trust under bankruptcy or insolvency laws; or
(d) default in the observance or performance of any material covenant or
condition of the Debenture Indentures and continuance of such default for a
period of 30 days after notice in writing has been given by the Debenture
Trustee to the Trust specifying such default and requiring the Trust to rectify
the same.  If an Event of Default has occurred and is continuing, the
Debenture Trustee may, in its discretion, and shall upon request of holders of
not less than 25 percent of the principal amount of the applicable Convertible
Debentures then outstanding, declare the principal of and interest on all
outstanding such Convertible Debentures to be immediately due and
payable.  In certain cases, the holders of more than 50 percent of the
principal amount of the applicable Convertible Debentures then outstanding may,
on behalf of the holders of all such Convertible Debentures, waive any Event of
Default and/or cancel any such declaration upon such terms and conditions as
such holders shall prescribe.
  Offers
for Debentures
  The
Debenture Indentures contain provisions to the effect that if an offer is made
for any series of Convertible Debentures, which is a take-over bid for such
series of Convertible Debentures within the meaning of the Securities Act (Alberta) and
not less than 90 percent of such Convertible Debentures (other than Convertible
Debentures held at the date of the take-over bid by or on behalf of the offeror
or associates or affiliates of the offeror) are taken up and paid for by the
offeror, the offeror will be entitled to acquire the Convertible Debentures held
by the holders of such series of Convertible Debentures who did not accept the
offer on the terms offered by the offeror.
  Modification
  The
rights of the holders of the Convertible Debentures may be modified in
accordance with the terms of the Debenture Indentures.  For that
purpose, among others, the Debenture Indentures contain certain provisions which
will make binding on all Convertible Debenture holders' resolutions passed at
meetings of the holders of Convertible Debentures by votes cast thereat by
holders of not less than 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.
   24
  Limitation
on Non-Resident Ownership
  The
Debenture Trustee may require declarations as to the jurisdictions in which
beneficial owners of Convertible Debentures are resident.  If the
Debenture Trustee becomes aware as a result of requiring such declarations as to
beneficial ownership, that the beneficial owners of 49 percent of the Trust
Units then outstanding (40 percent in the case of the 6.5% 2006 Debentures and
not more than half in the case of the 8% 2005 Debentures and the 7.2%
Debentures), on a fully diluted basis, are, or may be, Non-Residents or that
such a situation is imminent, the Debenture Trustee may make a public
announcement thereof and shall not register a transfer of Convertible Debentures
to a person unless the person provides a declaration that the person is not a
Non-Resident.  If, notwithstanding the foregoing, the Debenture
Trustee determines that a majority of the Trust Units are held by Non-Residents,
the Debenture Trustee may send a notice to Non-Resident holders of Convertible
Debentures, chosen in inverse order to the order of acquisition or registration
of the Convertible Debentures or in such manner as the Debenture Trustee may
consider equitable and practicable, requiring them to sell their Convertible
Debentures or a portion thereof within a specified period of not less than 60
days.  If the Convertible Debenture holders receiving such notice have
not sold the specified number of Convertible Debentures or provided the
Debenture Trustee with satisfactory evidence that they are not Non-Residents
within such period, the Debenture Trustee may, on behalf of such holder of
Convertible Debentures, and in the interim shall, suspend the rights attached to
such Convertible Debentures.  Upon such sale the affected holders
shall cease to be holders of Convertible Debentures, and their rights shall be
limited to receiving the net proceeds of sale upon surrender of such Convertible
Debentures.
  Book-Entry
System for Convertible Debentures
  The
Convertible Debentures (other than the 8% 2005 Debentures) are issued in
"book-entry only" form and must be purchased or transferred through a
participant in the depository service of CDS & Co.  The
Convertible Debentures (other than the 8% 2005 Debentures) are evidenced by a
single book-entry only certificate.  Registration of interests in and
transfers of the Convertible Debentures (other than the 8% 2005 Debentures) is
made only through the depository service of CDS & Co.
  The 8%
2005 Debentures are issued as fully registered debentures in certificated form
and beneficial holders of 8% 2005 Debentures may receive definitive certificates
representing their interest in 8% 2005 Debentures.
  Ratings
  Penn West
has not asked for nor has received a stability rating, and it is not aware that
it has received any other kind of rating, including a provisional rating, from
one or more approved rating organizations for outstanding securities of Penn
West, which rating or ratings continue in effect.
  Trust
Indenture
  The Trust
Indenture, among other things, provides for the calling of meetings of
Unitholders, the conduct of business thereof, notice provisions, the appointment
and removal of the Trustee and the form of Trust Unit
certificates.  The Trust Indenture may be amended from time to
time.  Substantive amendments to the Trust Indenture, including early
termination of the Trust and the sale or transfer of our property as an entirety
or substantially as an entirety, requires approval by special resolution of the
Unitholders.  See "Information Relating to the Trust – Meetings and
Voting" below.
  The
following is a summary of certain provisions of the Trust
Indenture.  For a complete description of such indenture, reference
should be made to the Trust Indenture, a copy of which (including all amendments
thereto) has been filed on SEDAR at www.sedar.com.
  Trustee
  CIBC
Mellon Trust Company was appointed our trustee on May 27, 2005, and also acts as
the transfer agent for the Trust Units.  The Trustee is responsible
for, among other things, accepting subscriptions for Trust Units and issuing
Trust Units pursuant thereto, maintaining our books and records and providing
timely reports to holders of Trust Units.  The Trust Indenture
provides that the Trustee shall exercise its powers and carry out its functions
thereunder as Trustee honestly, in
   25
  good
faith and in the Trust's best interests and in the best interest of the
Unitholders and, in connection therewith, shall exercise that degree of care,
diligence and skill that a reasonably prudent trustee would exercise in
comparable circumstances.
  In 2008,
the Unitholders appointed the Trustee for an additional three-year
term.  The Unitholders are required to re-appoint or appoint a
successor to the Trustee at the annual meeting of Unitholders three years
following the re-appointment or appointment of the successor to the
Trustee.  The Trustee may also be removed by special resolution of the
Unitholders.  Such resignation or removal becomes effective upon the
acceptance or appointment of a successor trustee.
  PWPL
presently administers the Trust on behalf of the Trustee.  PWPL, on
behalf of the Trustee, keeps such books and records as are necessary for the
proper recording of the Trust's business transactions.
  The Trust
Indenture provides that the Trustee shall be under no liability for any action
or failure to act unless such liabilities arise out of the Trustee's negligence,
wilful default or fraud.  The Trustee is indemnified out of the
Trust's assets for any liabilities relating to any taxes or other government
charges imposed upon the Trustee or in consequence of its performance of its
duties unless such liabilities arise principally and directly out of gross
negligence, wilful default or fraud of the Trustee, but has no additional
recourse against Unitholders.  In addition, the Trust Indenture
contains other customary provisions limiting the liability of the
Trustee.
  The Trust
Indenture also provides that the Trustee may without Unitholder approval amend
the articles of PWPL to issue shares of PWPL which are exchangeable for Trust
Units.  There are no exchangeable shares issued or
outstanding.
  Future
Offerings
  The Trust
Indenture provides that Trust Units, including rights, warrants and other
securities to purchase, to convert into or to exchange into Trust Units, may be
created, issued, sold and delivered on such terms and conditions and at such
times as the Trustee, upon the recommendation of the Board of Directors, may
determine.  The Trust Indenture also provides that PWPL may authorize
the creation and issuance of debentures, notes and other evidences of
indebtedness by the Trust, which debentures, notes or other evidences of
indebtedness may be created and issued from time to time on such terms and
conditions to such persons and for such consideration as the Board of Directors
may determine.
  Meetings
and Voting
  Meetings
of the Unitholders will be held annually.  Special meetings of
Unitholders may be called at any time by the Trustee and shall be called by the
Trustee upon the written request of Unitholders holding in aggregate not less
than 20 percent of the Trust Units.  Notice of all meetings of
Unitholders shall be given to Unitholders at least 21 days prior to the
meeting.
  Unitholders
will be entitled at each annual meeting to appoint the Trust's auditors and to
elect all the members of the Board of Directors.
  Our
Management
  The Board
of Directors has generally been delegated all of the Trust's significant
management decisions pursuant to the Trust Indenture and the Administration
Agreement.  For more information, see "Corporate
Governance".
  PWPL has
accepted all such delegation and has agreed that, in respect of such matters, it
shall carry out its functions honestly, in good faith and in the Trust's best
interests and the best interests of the Unitholders and, in connection
therewith, shall exercise that degree of care, diligence and skill that a
reasonable person would exercise in comparable circumstances.
  Limitation
on Non-Resident Ownership
  In order
for the Trust to maintain its status as a mutual fund trust under the Tax Act,
it must not be established or maintained primarily for the benefit of
Non-Residents unless it satisfies the requirements of certain
exceptions.  The Trust Indenture provides that Penn West will use its
best commercial efforts to maintain its status as a mutual fund trust under the
Tax Act.  Generally speaking, the Tax Act provides that a trust will
permanently lose its "mutual fund trust" status (which is essential to the
income trust structure) if it is established or maintained primarily for the
benefit of Non-Residents (which is generally
   26
  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.
  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.
   27
  Termination
of the Trust
  The
Unitholders may vote to terminate the Trust at any meeting of the Unitholders,
subject to the following: (a) a vote may only be held if requested in
writing by the holders of not less than 20 percent of the Trust Units;
(b) a quorum of 50 percent of the issued and outstanding Trust Units is
present in person or by proxy; and (c) the termination must be approved by
special resolution of the Unitholders.
  Unless
the Trust is earlier terminated or extended by vote of the Unitholders, the
Trustee shall commence to wind-up the affairs of the Trust on December 31,
2099.  In the event that the Trust is wound-up, the Trustee will
liquidate all of the Trust's assets, pay, retire, discharge or make provision
for some or all of the Trust's obligations and then distribute the remaining
proceeds of sale to Unitholders.
  Reporting
to Unitholders
  Penn
West's financial statements will be audited annually by an independent
recognized firm of chartered accountants.  Our audited financial
statements, together with the report of such chartered accountants, will be
mailed by the Trustee to Unitholders if previously requested and, if previously
requested, the unaudited interim financial statements will be mailed to
Unitholders within the periods prescribed by securities
legislation.  Penn West's year end is December 31.  We
are also subject to the continuous disclosure obligations under all applicable
securities legislation.
  Unitholders
are entitled to inspect, during normal business hours, at the offices of the
Trustee, and upon payment of reasonable reproduction costs, to receive
photocopies of the Trust Indenture and a listing of the registered holders of
Trust Units.
  CORPORATE GOVERNANCE
  General
  In
general, PWPL has been delegated responsibility for substantially all of the
management decisions of Penn West.  The Unitholders are entitled to
elect all of the members of the Board of Directors of PWPL pursuant to the terms
of the Trust Indenture.
  Trust
Indenture
  Pursuant
to the Trust Indenture, Unitholders are entitled to direct the manner in which
the Trust will vote its common shares in PWPL at all meetings in respect of
matters relating to the election of the directors of PWPL, approving its
financial statements and appointing auditors of PWPL who shall be the same as
the Trust's auditors.  Prior to the Trust voting its common shares in
PWPL in respect of such matters, each Unitholder is entitled to vote in respect
of the matter on the basis of one vote per Trust Unit held, and the Trust is
required to vote its common shares in PWPL in accordance with the result of the
vote of Unitholders.
  Decision
Making
  The Board
of Directors has a mandate to supervise the management of the Trust's business
and affairs, PWPL and the Trust's other direct or indirect Subsidiaries and to
act with a view to the Trust's best interest.  The Board of Directors'
mandate includes:  (i) any offering of securities; (ii) ensuring
compliance with all applicable laws, including in relation to an offering of
securities; (iii) all matters relating to the content of any documents relating
to an offering of securities, the accuracy of the disclosure contained therein,
and the certification thereof; (iv) all matters concerning the terms of, and
amendment from time to time of, material contracts; (v) all matters concerning
any subscription agreement or underwriting or agency agreement providing for the
sale or issue of Trust Units or securities convertible for or exchangeable into
Trust Units or rights to acquire Trust Units; (vi) all matters relating to the
redemption of Trust Units; (vii) all matters relating to the voting rights on
any investments; (viii) all matters relating to the specific powers and
authorities as set forth in the Trust Indenture; (ix) the adoption of a
Unitholder rights plan and other miscellaneous matters relating to the
maximization of Unitholder value; and (x) all matters relating to amending
PWPL's articles to create exchangeable shares.  The Board of Directors
holds regularly
   28
  scheduled
meetings at least quarterly to review the business and affairs of the Trust's
Subsidiaries and make any necessary decisions relating thereto.
  The Trust
Indenture gives to the Board of Directors the authority to exercise the rights,
powers and privileges for all matters relating to the maximization of Unitholder
value in the context of a take-over bid (an "Offer") including any
Unitholder rights protection plan, any defensive action to an Offer, any
directors circular in response to an Offer, any regulatory or court proceeding
relating to an Offer and any related or ancillary matter.
  Distributions
and Distribution Policy
  Cash
distributions are made on the 15th day
(or if such date is not a business day, on the preceding business day) following
the end of each calendar month to Unitholders of record on the last business day
of each such calendar month or such other date as determined from time to time
by the Trustee.
  The Board of Directors (on behalf of
the Trust) reviews the distribution policy from time to
time.  Distributions are not guaranteed and the amount that we
distribute per Trust Unit on a monthly basis may be reduced from time to time,
or even eliminated.  The actual amount distributed will be dependent
on various factors, including the commodity price environment, the amount of
capital expenditures that we make, our production levels and numerous other
economic and operational factors, many of which are beyond our
control.  The amount of distributions that we make (if any) is at the
discretion of the Board of Directors of PWPL.  See "Risk
Factors".  The current distribution policy targets the use of
approximately 60 percent to 70 percent of funds flow for distribution
to Unitholders.  Depending upon various factors, including commodity
prices and the size of Penn West's capital budget, it is expected that
approximately 30 percent to 40 percent of funds flow will fund all or
a portion of Penn West's annual capital expenditure program, including
exploration, exploitation expenditures and minor property acquisitions, but
excluding major acquisitions.
  Distributions
are normally announced on a monthly basis in the context of prevailing and
anticipated commodity prices.  During periods of volatile commodity
prices, we may vary the distribution rate monthly.  On January 14,
2009, we announced that in light of our intended 2009 capital expenditure levels
and the continuing weak commodity price environment, the Board of Directors had
approved a reduction to our monthly distribution to Unitholders from $0.34 per
Trust Unit per month to $0.23 per Trust Unit per month for the next two months
(subject to changes in commodity prices, production levels and capital
expenditures), commencing with the distribution paid on February 13, 2009 to
Unitholders of record on January 30, 2009.  On March 26, 2009, we
subsequently announced that in light of our revised 2009 capital expenditure
levels and the continuing weak commodity price environment, the Board of
Directors had approved a further reduction to our monthly distribution to
Unitholders from $0.23 per Trust Unit per month to $0.15 per Trust Unit per
month, subject to changes in commodity prices, production levels and capital
expenditures, commencing with the distribution to be paid on May15, 2009 to Unitholders
of record on April 30, 2009.
  Pursuant
to the provisions of the Trust Indenture all taxable income earned by Penn West
in a fiscal year, not previously distributed in that fiscal year, must be
distributed to Unitholders of record on December 31 of such
year.  This excess income, if any, will be allocated to Unitholders of
record at December 31 but the right to receive this income, if the amount is not
determined and declared payable at December 31, will trade with the Trust Units
until determined and declared payable in accordance with the rules of the
TSX.  To the extent that a Unitholder trades Trust Units in this
period they will be allocated such income but will dispose of their right to
receive the cash or Trust Units comprising such a distribution.
  The
credit agreement governing PWPL's syndicated credit facility and the note
purchase agreements governing PWPL's 2007 Senior Notes, 2008 Senior Notes and
2008 Pounds Sterling Senior Notes each contain provisions which restrict the
ability of the Trust to pay distributions to Unitholders in the event of the
occurrence of certain events of default.  For further information
regarding the credit agreement governing our syndicated credit facility,
reference is made to Note 6 (Long-Term Debt) of our consolidated financial
statements for the year ended December 31, 2008.  For further
information regarding the note purchase agreements governing PWPL's 2007 Senior
Notes, 2008 Senior Notes and 2008 Pounds Sterling Senior Notes, reference is
made to note 6 (Long-Term Debt) of our consolidated financial statements
for the year ended December 31, 2008.  Note 6 (Long-Term
Debt) of our consolidated financial statements for the year ended
December 31, 2008 is incorporated by reference in this Annual Information
Form.  Our consolidated financial statements for the year ended
December 31, 2008 are filed on SEDAR at www.sedar.com.
   29
  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).John
      A. Brussa
                Alberta,
      Canada
              
              Chairman
      of the Board of Directors Director since April 21, 1995
              
              Senior
      Partner, Burnet, Duckworth & Palmer LLP (barristers and
      solicitors).Daryl
      Gilbert(2)(3)(5)
                Alberta,
      Canada
              
              Director
      since January 11, 2008
              
              Independent
      business consultant since 2005 and a corporate director of a number of
      companies.  President and Chief Executive Officer of GLJ
      Petroleum Consultants Ltd. (formerly Gilbert Laustsen Jung Associates
      Ltd.) (an engineering consulting firm) until 2005.Shirley
      A. McClellan(1)(4)(5)
                Alberta,
      Canada
              
              Director
      since June 8, 2007
              
              Distinguished
      Scholar in Residence at the University of Alberta for the Faculties of
      Agriculture and Rural Economy and the School of
      Business.  Independent businesswoman since
      2007.  Prior thereto, Deputy Premier of the Province of Alberta
      from 2001 to 2007 and Minister of Finance of the Province of Alberta from
      2004 to 2007.Frank
      Potter(1)(4)(6)
                Ontario,
      Canada
              
              Director
      since June 30, 2006
              
              Chairman
      of Emerging Markets Advisors, Inc. (an investment consulting
      firm).R.
      Gregory Rich(2)(4)
                Texas,
      United States
              
              Director
      since January 11, 2008
              
              Principal
      of Blackrock Energy Associates (an energy consulting and investment firm),
      since October 2002.
   30
 Name,
      Province/State and Country of Residence
                
                Positions
      and Offices Held
                
                Principal
      Occupations
                    during
      the Five Preceding
Years
 Jack
      Schanck(3)(5)
                Texas,
      United States
              
              Director
      since June 2, 2008
              
              Managing
      Partner of Tecton Energy, LLC since 2007, a Texas-based oil and natural
      gas exploration and production company.  Prior thereto, Chief
      Executive Officer of SouthView Energy LLC, an oil and natural gas
      investment company, from 2005 to 2007.  Prior thereto, Co-Chief
      Executive Officer of Samson Investment Company.James
      C. Smith(1)(2)(3)
                Alberta,
      Canada
              
              Director
      since May 31, 2005
              
              Independent
      director and consultant to a number of public and private oil and gas
      companies.Murray
      Nunns
                Alberta,
      Canada
              
              President
      and Chief Operating Officer
              
              President
      and Chief Operating Officer of PWPL since February 8,
      2008.  Prior thereto, director of PWPL and Executive Chairman of
      Monterey Exploration Ltd., a private oil and gas company.  Prior
      thereto, a variety of management positions at Rio Alto Exploration Ltd., a
      public oil and gas company.Todd
      H. Takeyasu
                Alberta,
      Canada
              
              Executive
      Vice President and Chief Financial Officer
              
              Executive
      Vice President and Chief Financial Officer of PWPL since February 8,
      2008.  Prior thereto, Senior Vice President, Finance – Treasury
      of PWPL since January 11, 2008.  Prior thereto, Senior Vice
      President and Chief Financial Officer of PWPL since 2006.  Prior
      thereto, Vice President, Finance of PWPL since 2005.  Prior
      thereto, Treasurer of PWPL.David
      W. Middleton
                Alberta,
      Canada
              
              Executive
      Vice President, Engineering and Corporate Development
              
              Executive
      Vice President, Engineering and Corporate Development of PWPL since
      November 3, 2008.  Prior thereto, Executive Vice President,
      Operations and Corporate Development of PWPL since February 8,
      2008.  Prior thereto, Chief Operating Officer of PWPL since
      January 11, 2008.  Prior thereto, Executive Vice President
      and Chief Operating Officer of PWPL since 2005.  Prior thereto,
      Senior Vice President, Production of PWPL since 2003.Mark
      P. Fitzgerald
                Alberta,
      Canada
              
              Senior
      Vice President, Production
              
              Senior
      Vice President, Production of PWPL since November 3,
      2008.  Prior thereto, Senior Vice President, Engineering of PWPL
      since January 11, 2008.  Prior thereto, Vice President,
      Operations of Canetic since January 2006.  Prior thereto, Vice
      President, Operations of Acclaim since February 2005.  Prior
      thereto, Vice President, Engineering of Acclaim (since 2004) and Manager,
      Western District of Acclaim (from 2003 to 2004).Thane
      A.E. Jensen
                Alberta,
      Canada
              
              Senior
      Vice President, Operations Engineering
              
              Senior
      Vice President, Operations Engineering of PWPL since November 3,
      2008.  Prior thereto, Senior Vice President, Exploration and
      Development of PWPL since 2005.  Prior thereto, Vice President,
      Engineering of PWPL since 2004.
  31
  Name,
      Province/State and Country of Residence
                  
                  Positions
      and Offices Held
                  
                  Principal
      Occupations
                      during
      the Five Preceding
Years
 Keith
      Luft
                  Alberta,
      Canada
                
                General
      Counsel and Senior Vice President, Stakeholder Relations
                
                General
      Counsel and Senior Vice President, Stakeholder Relations of PWPL since
      February 8, 2008.  Prior thereto, Senior Vice President,
      Stakeholder Relations of PWPL since January 11, 2008.  Prior
      thereto, Vice President, Land and Legal of PWPL since
      2006.  Prior thereto, Senior Solicitor of Conoco Phillips Canada
      Ltd. / Burlington Resources Canada Ltd. (an oil and gas company) since May
      2004.Hilary
      Foulkes
                  Alberta,
      Canada
                
                Senior
      Vice-President, Business Development
                
                Senior
      Vice-President, Business Development of PWPL since April 29,
      2008.  Prior thereto, a Managing Director with the investment
      banking firm, Scotia Waterous for 8 years.  Prior thereto,
      various positions as a geologist in exploration and development roles with
      Gulf Canada Resources.
  Notes:
  (1)
              Member
      of the Audit Committee of the Board of
  Directors.
 (2)
              Member
      of the Human Resources and Compensation Committee of the Board of
      Directors.
 (3)
              Member
      of the Reserves Committee of the Board of
  Directors.
 (4)
              Member
      of the Governance Committee of the Board of
  Directors.
 (5)
              Member
      of the Health, Safety and Environment Committee of the Board of
      Directors.
 (6)
              Member
      of the Acquisitions and Divestments Committee of the Board of
      Directors.
  As at
March 26, 2009, the directors and executive officers of PWPL, as a group,
beneficially owned, or controlled or directed, directly or indirectly,
approximately one million Trust Units or less than one percent of the issued and
outstanding Trust Units.
  Cease
Trade Orders, Bankruptcies, Penalties or Sanctions
  Except as
otherwise disclosed herein,no director or executive
officer of PWPL (nor any personal holding company of any of such persons) is, as
of the date of this Annual Information Form, or was within ten years before the
date of this Annual Information Form, a director, Chief Executive Officer or
Chief Financial Officer of any company (including PWPL), that:
  (a)
              was
      subject to a cease trade order (including a management cease trade order),
      an order similar to a cease trade order or an order that denied the
      relevant company access to any exemption under securities legislation, in
      each case that was in effect for a period of more than 30 consecutive days
      (collectively, an "Order") that was issued
      while the director or executive officer was acting in the capacity as
      director, Chief Executive Officer or Chief Financial Officer;
      or
  (b)
              was
      subject to an Order that was issued after the director or executive
      officer ceased to be a director, Chief Executive Officer or Chief
      Financial Officer and which resulted from an event that occurred while
      that person was acting in the capacity as director, Chief Executive
      Officer or Chief Financial Officer.
  Daryl
Gilbert is a director of Globel Direct, Inc., which was subject to a cease trade
order issued by the British Columbia Securities Commission on November 20, 2002
and the Alberta Securities Commission on November 22, 2002 for delay in filing
financial statements.  The required financial statements were filed
and the cease trade orders were revoked effective December 23,
2002.  The company sought and received protection under CCAA in June
2007, and after a failed restructuring effort, a receiver was appointed by one
of the company's lenders in December 2007.  The company has since
ceased operations and is delisted.
   32
  Except as
otherwise disclosed herein, no director or executive officer of PWPL (nor any
personal holding company of any of such persons), or shareholder holding a
sufficient number of securities of Penn West to affect materially the control of
Penn West:
  (a)
              is,
      as of the date of this Annual Information Form, or has been within the ten
      years before the date of this Annual Information Form, a director or
      executive officer of any company (including PWPL) that, while that person
      was acting in that capacity, or within a year of that person ceasing to
      act in that capacity, became bankrupt, made a proposal under any
      legislation relating to bankruptcy or insolvency or was subject to or
      instituted any proceedings, arrangement or compromise with creditors or
      had a receiver, receiver manager or trustee appointed to hold its assets;
      or
  (b)
              has,
      within the ten years before the date of this Annual Information Form,
      become bankrupt, made a proposal under any legislation relating to
      bankruptcy or insolvency, or become subject to or instituted any
      proceedings, arrangement or compromise with creditors, or had a receiver,
      receiver manager or trustee appointed to hold the assets of the director,
      executive officer or shareholder.
  John A.
Brussa was a director of Imperial Metals Limited, a corporation engaged in both
oil and gas and mining operations, in the year prior to that corporation
implementing a plan of arrangement under the Company Act (British
Columbia) and under the Companies' Creditors Arrangement
Act (Canada) which resulted in the separation of its two
businesses.  The reorganization resulted in the creation of two public
corporations, Imperial Metals Corporation and IEI Energy Inc. (subsequently
renamed Rider Resources Ltd.), both of which were listed on the
TSX.
  James C.
Smith was, from May 1999 to March 2000, Vice President and Chief Financial
Officer of Probe Exploration Inc., an oil and gas company listed on the
TSX.  Mr. Smith joined Probe Exploration Inc. in order to assist
management and the Board of Directors of the company in their efforts to
restructure the company's finances or sell assets to improve its financial
situation.  Such efforts did not succeed and the company's lender
appointed a receiver in March 2000.
  No
director or executive officer of PWPL (nor any personal holding company of any
of such persons), or shareholder holding a sufficient number of securities of
Penn West to affect materially the control of Penn West, has been subject
to:
  (a)
              any
      penalties or sanctions imposed by a court relating to securities
      legislation or by a securities regulatory authority or has entered into a
      settlement agreement with a securities regulatory authority;
      or
  (b)
              any
      other penalties or sanctions imposed by a court or regulatory body that
      would likely be considered important to a reasonable investor in making an
      investment decision.
  Conflicts
of Interest
  The Board
of Directors has adopted a Code of Business Conduct and Ethics and a Code of
Ethics for Officers and Senior Financial Management (the "Codes").  In
general, the private investment activities of employees, directors and officers
are not prohibited; however, should an existing investment pose a potential
conflict of interest, the potential conflict is required by the Codes to be
disclosed to the President, Chief Executive Officer or the Board of
Directors.  Any other activities posing a potential conflict of
interest are also required by the Codes to be disclosed to the Chief Executive
Officer or the Board of Directors.  Any such potential conflicts of
interests will be dealt with openly with full disclosure of the nature and
extent of the potential conflicts of interests with Penn West.
  It is
acknowledged in the Codes that the directors may be directors or officers of
other entities engaged in the oil and gas business, and that such entities may
compete directly or indirectly with Penn West.  Passive investments in
public or private entities of less than one per cent of the outstanding shares
will not be viewed as "competing" with Penn West.  No executive
officer or employee of PWPL should be a director or officer of any entity
engaged in the oil and gas business unless expressly authorized by the Board of
Directors.  Any director of PWPL who is actively engaged in the
management of, or who owns an investment of one per cent or more of the
outstanding shares, in public or private entities shall disclose such holding to
the Board of Directors.  In the event that any circumstance should
arise as a result of such positions or investments being held or otherwise which
in the opinion of the Board of Directors constitutes a conflict of interest
which reasonably affects such person's ability to act with a view to the best
interests of Penn West, the Board of Directors will take such
actions
   33
  as are
reasonably required to resolve such matters with a view to the best interests of
Penn West.  Such actions, without limitation, may include excluding
such directors, officers or employees from certain information or activities of
Penn West.
  The ABCA
provides that in the event that an officer or director is a party to, or is a
director or an officer of, or has a material interest in any person who is a
party to, a material contract or material transaction or proposed material
contract or proposed material transaction, such officer or director shall
disclose the nature and extent of his or her interest and shall refrain from
voting to approve such contract or transaction.
  As of the
date hereof, Penn West is not aware of any existing or potential material
conflicts of interest between Penn West or a Subsidiary of Penn West and any
director or officer of Penn West or of any Subsidiary of Penn West, including
PWPL.
  Promoters
  No person
or company has been, within the two most recently completed financial years or
during the current financial year, a "promoter" (as defined in the Securities Act (Ontario)) of
Penn West or of a Subsidiary of Penn West.
  AUDIT COMMITTEE
DISCLOSURES
  National
Instrument 52-110 ("NI
52-110") relating to audit committees has mandated certain disclosures
for inclusion in this Annual Information Form.  The text of the Audit
Committee's mandate is attached as Appendix "B" to this Annual Information
Form.
  Composition
of the Audit Committee and Relevant Education and Experience
  The
members of the Audit Committee are James C. Smith, chairman, and James E.
Allard, Shirley A. McClellan and Frank Potter, each of whom is independent
and financially literate within the meaning of NI 52-110.  The
following comprises a brief summary of each member's education and experience
that is relevant to the performance of his responsibilities as an Audit
Committee member.
  James
C. Smith (Chairman)
  Mr. Smith
is a Chartered Accountant with over 35 years of experience in public accounting
and industry.  Since 1998, he has been a business consultant and
independent director to a number of public and private companies operating in
the oil and natural gas industry.  From February 2002 to June 2006, he
served as the Vice-President and Chief Financial Officer of Mercury Energy
Corporation, a private oil and natural gas company.  Mr. Smith also
held the position of Chief Financial Officer of Segue Energy Corporation, a
private oil and natural gas company, from January 2001 to August
2003.  From 1999 to 2000, Mr. Smith was the Vice-President and Chief
Financial Officer of Probe Exploration Inc., a publicly traded oil and natural
gas company.  Mr. Smith served as the Vice-President and Chief
Financial Officer of Crestar Energy Inc. from its inception in 1992 until 1998,
during which time the company completed an initial public offering, was listed
on the TSX and completed several major debt and equity financing
transactions.
  James
E. Allard
  Mr.
Allard is an independent director and business advisor.  He has a
Bachelor of Science degree in Business Administration from the University of
Connecticut and completed the Advanced Management Program at Harvard
University.  Mr. Allard has focused his career on international
finance in the petroleum industry for the past 40 years, during which time he
has served as the Chief Executive Officer, Chief Financial Officer and/or a
director of a number of publicly traded and private companies.  Over
the past nine years he has served on the board of the Alberta Securities
Commission, acted as the sole external trustee and advisor to a mid-sized
pension plan and served as a director and advisor to several
companies.  From 1981 to 1995, Mr. Allard served as a senior executive
officer of Amoco Corporation and as a director of Amoco Canada, which at that
time was Canada's largest natural gas producer.
   34
  Frank
Potter
  Mr.
Potter has a background in international banking in Europe, the Middle East and
the United States.  He managed the international business of one of
Canada's principal banks before being appointed Executive Director of the World
Bank in Washington where he served for nine years.  Mr. Potter
subsequently served as a Senior Advisor at the Department of Finance for the
Canadian government.  He is currently the Chairman of Emerging Markets
Advisors, Inc., a Toronto based consultancy that assists corporations in making
and managing direct investments internationally.  Mr. Potter serves on
a number of boards, including Canadian Tire Corporation, Limited, the Royal
Ontario Museum and Softchoice Corporation.
  Shirley
A. McClellan
  Mrs.
McClellan is a Distinguished Scholar in Residence at the University of Alberta
for the Faculties of Agriculture and Rural Economy and the School of
Business.  She lectures primarily in Rural Economy and the School of
Business.  Mrs. McClellan brings to Penn West the experience gained
over 20 years of distinguished service to the Province of
Alberta.  Her career included the offices of Deputy Premier of Alberta
from 2001 to 2007, Minister of Finance of Alberta from 2004 to 2007 and Chair of
the Treasury Board and Vice-Chair of the Agenda and Priorities Committee of the
Government of Alberta.  Mrs. McClellan served a total of six terms as
a Member of the Alberta Legislative Assembly representing the constituency of
Drumheller-Stettler.  Over this time period, she held numerous other
portfolios, including Minister of Agriculture, Food and Rural Development,
Minister of International and Intergovernmental Relations, Minister of Community
Development, and Minister of Health.
  Pre-Approval
Policies and Procedures for Non-Audit Services
  The terms
of the engagement of Penn West's external auditors to provide audit services,
including the budgeted fees for such audit services and the representations and
disclaimer relating thereto, must be pre-approved by the entire Audit
Committee.
  With
respect to any engagements of Penn West's external auditors for non-audit
services, Penn West must obtain the approval of the Audit Committee or the
Chairman of the Audit Committee prior to retaining the external auditors to
complete such engagement.  If such pre-approval is provided by the
Chairman of the Audit Committee, the Chairman shall report to the Audit
Committee on any non-audit service engagement pre-approved by him at the Audit
Committee's first scheduled meeting following such pre-approval.
  If, after
using its reasonable best efforts, Penn West is unable to contact the Chairman
of the Audit Committee on a timely basis to obtain the pre-approval contemplated
by the preceding paragraph, Penn West may obtain the required pre-approval from
any other member of the Audit Committee, provided that any such Audit Committee
member shall report to the Audit Committee on any non-audit service engagement
pre-approved by him at the Audit Committee's first scheduled meeting following
such pre-approval.
  External
Auditor Service Fees
  The
following table summarizes the fees paid to KPMG LLP for external audit and
other services during the periods indicated.
  Year
              
              Audit
      Fees(1)
                  ($)
              
              
              Audit
      Related Fees(2)
                  ($)
              
              
              Tax
      Fees(3)
                  ($)
              
              
              All
      Other Fees(4)
                  ($)2008
              
              
              1,550,000
              
              
              
              562,500
              
              
              
              3,712
              
              
              
              -2007
              
              
              1,045,000
              
              
              
              120,000
              
              
              
              7,914
              
              
              
              -
  Notes:
  (1)
              The
      aggregate fees billed by our external auditor in each of the last two
      fiscal years for audit services, including Sarbanes – Oxley compliance
      related services.
 (2)
              The
      aggregate fees billed in each of the last two fiscal years by our external
      auditor for assurance and related services that are reasonably related to
      the performance of the audit or review of our financial statements (and
      not included in audit services fees in note (1)).  The services
      comprising the fees disclosed under this category principally consisted of
      French translation services and matters related to the corporate
      acquisitions completed in 2008.
   
  35
 (3)
                The
      aggregate fees billed in each of the last two fiscal years by our external
      auditor for professional services for tax compliance, tax advice and tax
      planning.  The services comprising the fees disclosed under this
      category principally consisted of assistance and advice in relation to the
      communication of the taxability of distributions to
      Unitholders.
 (4)
                The
      aggregate fees billed in each of the last two fiscal years by our external
      auditor for products and services not included under the headings "Audit
      Fees", "Audit Related Fees" and "Tax
Fees".
 Reliance
on Exemptions
  At no
time since the commencement of Penn West's most recently completed financial
year has Penn West relied on any of the exemptions contained in
Sections 2.4, 3.2, 3.4 or 3.5 of NI 52-110, or an exemption from NI
52-110, in whole or in part, granted under Part 8 thereof.  In
addition, at no time since the commencement of Penn West's most recently
completed financial year has Penn West relied upon the exemptions in Subsection
3.3(2) or Section 3.6 of NI 52-110.  Furthermore, at no time
since the commencement of Penn West's most recently completed financial year has
Penn West relied upon Section 3.8 of NI 52-110.
  Audit
Committee Oversight
  At no
time since the commencement of Penn West's most recently completed financial
year has a recommendation of the Audit Committee to nominate or compensate an
external auditor not been adopted by the Board of Directors of
PWPL.
  DISTRIBUTIONS TO
UNITHOLDERS
  During
the three most recently completed financial years, we have declared the
following amount of cash distributions per Trust Unit, each amount being paid in
the following month:
  Month
              
              2009
                  ($)
              
              
              2008
                  ($)
              
              
              2007
                  ($)
              
              
              2006
                  ($)January
              
              
              0.23
              
              
              
              0.34
              
              
              
              0.34
              
              
              
              0.31February
              
              
              0.23
              
              
              
              0.34
              
              
              
              0.34
              
              
              
              0.34March
              
              
              0.23
              
              
              
              0.34
              
              
              
              0.34
              
              
              
              0.34April
              
              
              -
              
              
              
              0.34
              
              
              
              0.34
              
              
              
              0.34May
              
              
              -
              
              
              
              0.34
              
              
              
              0.34
              
              
              
              0.34June
              
              
              -
              
              
              
              0.34
              
              
              
              0.34
              
              
              
              0.34July
              
              
              -
              
              
              
              0.34
              
              
              
              0.34
              
              
              
              0.34August
              
              
              -
              
              
              
              0.34
              
              
              
              0.34
              
              
              
              0.34September
              
              
              -
              
              
              
              0.34
              
              
              
              0.34
              
              
              
              0.34October
              
              
              -
              
              
              
              0.34
              
              
              
              0.34
              
              
              
              0.34November
              
              
              -
              
              
              
              0.34
              
              
              
              0.34
              
              
              
              0.34December
              
              
              -
              
              
              
              0.34
              
              
              
              0.34
              
              
              
              0.34Total
              
              
              0.69
              
              
              
              4.08
              
              
              
              4.08
              
              
              
              4.05
 
  36
  On
January 14, 2009, we announced that in light of our intended 2009 capital
expenditure levels and the continuing weak commodity price environment, we had
approved a reduction to our monthly distribution to Unitholders from $0.34 per
Trust Unit per month to $0.23 per Trust Unit per month for the next two months
(subject to changes in commodity prices, production levels and capital
expenditures), commencing with the distribution payable on February 13, 2009 to
Unitholders of record on January 30, 2009.  On March 26, 2009, we
subsequently announced that in light of our revised 2009 capital expenditure
levels and the continuing weak commodity price environment, the Board of
Directors had approved a further reduction to our monthly distribution to
Unitholders from $0.23 per Trust Unit per month to $0.15 per Trust Unit per
month, subject to changes in commodity prices, production levels and capital
expenditures, commencing with the distribution to be paid on May 15, 2009 to
Unitholders of record on April 30, 2009.  Future distributions are subject to
the discretion of the Board of Directors and may vary depending on, among other
things, the current and anticipated commodity price environment, our production
levels and the amount of capital expenditures that we make.  Cash
distributions to Unitholders are not assured or guaranteed.  See "Risk
Factors".
  MARKET FOR SECURITIES
  Units
  The Units
are listed and traded on the TSX under the symbol PWT.UN and on the NYSE under
the symbol PWE.  The following tables set forth certain trading
information for our Units in 2008 as reported by the TSX and the
NYSE.
  TSXUnit
      price ($)
              
              
              Unit
      price ($)Period
              
              High
              
              
              Low
              
              
              VolumeJanuary
              
              
              28.04
              
              
              
              24.45
              
              
              
              33,930,707February
              
              
              29.44
              
              
              
              26.10
              
              
              
              24,266,003March
              
              
              29.20
              
              
              
              26.97
              
              
              
              23,758,942April
              
              
              32.01
              
              
              
              28.35
              
              
              
              21,082,554May
              
              
              34.95
              
              
              
              29.66
              
              
              
              22,395,091June
              
              
              35.60
              
              
              
              31.96
              
              
              
              24,200,848July
              
              
              34.71
              
              
              
              29.13
              
              
              
              20,205,817August
              
              
              31.25
              
              
              
              28.51
              
              
              
              17,049,678September
              
              
              30.40
              
              
              
              22.91
              
              
              
              31,474,406October
              
              
              25.50
              
              
              
              15.05
              
              
              
              39,485,740November
              
              
              21.87
              
              
              
              15.28
              
              
              
              25,431,412December
              
              
              17.55
              
              
              
              12.93
              
              
              
              30,997,981
 
 
 NYSEUnit
      price (US$)
              
              
              Unit
      price (US$)Period
              
              High
              
              
              Low
              
              
              VolumeJanuary
              
              
              27.50
              
              
              
              23.52
              
              
              
              45,787,618February
              
              
              29.92
              
              
              
              25.99
              
              
              
              34,885,928March
              
              
              28.90
              
              
              
              26.30
              
              
              
              35,437,097April
              
              
              31.88
              
              
              
              27.60
              
              
              
              37,202,450May
              
              
              35.49
              
              
              
              29.10
              
              
              
              45,269,580June
              
              
              35.00
              
              
              
              31.50
              
              
              
              38,923,000July
              
              
              34.17
              
              
              
              28.92
              
              
              
              47,463,628August
              
              
              30.30
              
              
              
              26.62
              
              
              
              33,681,348September
              
              
              28.81
              
              
              
              22.00
              
              
              
              64,983,228October
              
              
              24.00
              
              
              
              13.00
              
              
              
              123,125,280November
              
              
              19.01
              
              
              
              11.86
              
              
              
              64,281,100December
              
              
              14.19
              
              
              
              9.97
              
              
              
              77,151,448
  
 37
  Convertible
Debentures Assumed Pursuant to the Vault Acquisition
  We
assumed the 7.2% 2006 Debentures and the 8% 2005 Debentures from Vault on
January 10, 2008 in connection with the Vault Acquisition.  The
7.2% 2006 Debentures and the 8% 2005 Debentures began trading on the TSX as our
securities on January 15, 2008 under the symbols "PWT.DB.E" and "PWT.DB.C",
respectively.
  7.2%
2006 Debentures
   The
following table sets forth certain trading information for our 7.2% 2006
Debentures in 2008 as reported by the TSX (with each unit of volume traded being
equal to $100 principal amount of 7.2% 2006 Debentures).
  TSXDebenture
      price ($)
              
              
              Debenture
      price ($)Period
              
              High
              
              
              Low
              
              
              VolumeJanuary
      (15-31)
              
              
              101.25
              
              
              
              100.29
              
              
              
              60,120February
              
              
              101.50
              
              
              
              100.76
              
              
              
              21,740March
              
              
              102.00
              
              
              
              100.65
              
              
              
              5,190April
              
              
              102.00
              
              
              
              100.50
              
              
              
              3,840May
              
              
              102.00
              
              
              
              99.75
              
              
              
              6,660June
              
              
              102.00
              
              
              
              101.00
              
              
              
              16,300July
              
              
              101.75
              
              
              
              101.50
              
              
              
              2,320August
              
              
              102.95
              
              
              
              101.00
              
              
              
              430September
              
              
              102.00
              
              
              
              101.25
              
              
              
              2,210October
              
              
              99.50
              
              
              
              90.00
              
              
              
              1,940November
              
              
              95.00
              
              
              
              79.00
              
              
              
              990December
              
              
              90.00
              
              
              
              82.00
              
              
              
              1,100
  8%
2005 Debentures
   The
following table sets forth certain trading information for our 8% 2005
Debentures in 2008 as reported by the TSX (with each unit of volume traded being
equal to $100 principal amount of 8% 2005 Debentures).
  TSXDebenture
      price ($)
              
              
              Debenture
      price ($)Period
              
              High
              
              
              Low
              
              
              VolumeJanuary
      (15-31)
              
              
              -
              
              
              
              -
              
              
              
              -February
              
              
              -
              
              
              
              -
              
              
              
              -March
              
              
              104.50
              
              
              
              104.50
              
              
              
              300April
              
              
              -
              
              
              
              -
              
              
              
              -May
              
              
              -
              
              
              
              -
              
              
              
              -June
              
              
              106.55
              
              
              
              104.00
              
              
              
              1,480July
              
              
              -
              
              
              
              -
              
              
              
              -August
              
              
              105.99
              
              
              
              105.99
              
              
              
              100September
              
              
              105.00
              
              
              
              104.03
              
              
              
              5,490October
              
              
              104.25
              
              
              
              104.25
              
              
              
              100November
              
              
              -
              
              
              
              -
              
              
              
              -December
              
              
              100.00
              
              
              
              100.00
              
              
              
              330
  Convertible
Debentures Assumed Pursuant to the Canetic Acquisition
  We
assumed the 6.5% 2005 Debentures, the 6.5% 2006 Debentures and the 8% 2004
Debentures from Canetic on January 11, 2008 in connection with the
completion of the Canetic Acquisition.  The 6.5% 2005 Debentures, the
6.5% 2006 Debentures and the 8% 2004 Debentures began trading on the TSX as our
securities on January 16, 2008 under the symbols
   38
  "PWT.DB.D",
"PWT.DB.F" and "PWT.DB.B", respectively.  We also assumed the 9.4%
convertible unsecured subordinated debentures from Canetic on January 11, 2008
in connection with the completion of the Canetic Acquisition; however, these
debentures were subsequently repaid on July 31, 2008 when they matured and are
no longer outstanding.
  6.5%
2005 Debentures
  The
following table sets forth certain trading information for our 6.5% 2005
Debentures in 2008 as reported by the TSX (with each unit of volume traded being
equal to $100 principal amount of 6.5% 2005 Debentures).
  TSXDebenture
      price ($)
              
              
              Debenture
      price ($)Period
              
              High
              
              
              Low
              
              
              VolumeJanuary
      (16-31)
              
              
              100.00
              
              
              
              98.00
              
              
              
              2,430February
              
              
              101.00
              
              
              
              99.00
              
              
              
              10,120March
              
              
              104.80
              
              
              
              100.50
              
              
              
              1,580April
              
              
              102.25
              
              
              
              101.00
              
              
              
              1,680May
              
              
              102.25
              
              
              
              101.10
              
              
              
              10,760June
              
              
              104.00
              
              
              
              102.00
              
              
              
              5,850July
              
              
              102.55
              
              
              
              100.00
              
              
              
              4,340August
              
              
              101.50
              
              
              
              100.00
              
              
              
              5,460September
              
              
              102.00
              
              
              
              100.00
              
              
              
              3,410October
              
              
              100.00
              
              
              
              90.00
              
              
              
              3,720November
              
              
              98.50
              
              
              
              92.00
              
              
              
              2,470December
              
              
              95.00
              
              
              
              90.00
              
              
              
              970
  6.5%
2006 Debentures
  The
following table sets forth certain trading information for our 6.5% 2006
Debentures in 2008 as reported by the TSX (with each unit of volume traded being
equal to $100 principal amount of 6.5% 2006 Debentures).
  TSXDebenture
      price ($)
              
              
              Debenture
      price ($)Period
              
              High
              
              
              Low
              
              
              VolumeJanuary
      (16-31)
              
              
              99.50
              
              
              
              97.00
              
              
              
              33,980February
              
              
              101.00
              
              
              
              97.00
              
              
              
              36,700March
              
              
              101.00
              
              
              
              99.00
              
              
              
              46,420April
              
              
              100.80
              
              
              
              97.25
              
              
              
              41,385May
              
              
              101.25
              
              
              
              98.50
              
              
              
              25,180June
              
              
              102.50
              
              
              
              100.00
              
              
              
              33,430July
              
              
              101.52
              
              
              
              100.50
              
              
              
              25,950August
              
              
              102.90
              
              
              
              95.00
              
              
              
              47,040September
              
              
              102.90
              
              
              
              98.50
              
              
              
              27,790October
              
              
              99.55
              
              
              
              69.00
              
              
              
              27,530November
              
              
              94.00
              
              
              
              75.00
              
              
              
              99,830December
              
              
              83.02
              
              
              
              73.00
              
              
              
              44,200
  8%
2004 Debentures
  The
following table sets forth certain trading information for our 8% 2004
Debentures in 2008 as reported by the TSX (with each unit of volume traded being
equal to $100 principal amount of 8% 2004 Debentures).
   39
  TSXDebenture
      price ($)
              
              
              Debenture
      price ($)Period
              
              High
              
              
              Low
              
              
              VolumeJanuary
      (16-31)
              
              
              101.50
              
              
              
              101.00
              
              
              
              640February
              
              
              104.03
              
              
              
              103.72
              
              
              
              680March
              
              
              -
              
              
              
              -
              
              
              
              -April
              
              
              105.12
              
              
              
              104.50
              
              
              
              1,780May
              
              
              113.51
              
              
              
              104.39
              
              
              
              1,050June
              
              
              116.68
              
              
              
              104.03
              
              
              
              1,350July
              
              
              110.19
              
              
              
              104.01
              
              
              
              820August
              
              
              104.50
              
              
              
              104.50
              
              
              
              30September
              
              
              104.75
              
              
              
              103.55
              
              
              
              390October
              
              
              103.55
              
              
              
              70.00
              
              
              
              1,440November
              
              
              100.00
              
              
              
              97.00
              
              
              
              1,950December
              
              
              100.00
              
              
              
              97.01
              
              
              
              2,390
  Penn West
does not have any classes of securities that are outstanding but that are not
listed or quoted on a market place.  In addition, to Penn West's
knowledge, no securities of Penn West are held in escrow, are subject to a
pooling agreement, or are subject to a contractual restriction on transfer
(except in respect of pledges made to lenders).
  INDUSTRY CONDITIONS
  The oil
and natural gas industry is subject to extensive controls and regulations
governing its operations (including land tenure, exploration, development,
production, refining, transportation, and marketing) imposed by legislation
enacted by various levels of government and with respect to pricing and taxation
of oil and natural gas by agreements among the governments of Canada, Alberta,
British Columbia, and Saskatchewan, all of which should be carefully considered
by investors in the oil and gas industry.  It is not expected that any
of these controls or regulations will affect our operations in a manner
materially different than they would affect other oil and gas companies of
similar size.  All current legislation is a matter of public record
and we are unable to predict what additional legislation or amendments may be
enacted.  Outlined below are some of the principal aspects of
legislation, regulations and agreements governing the oil and gas
industry.
  Pricing
and Marketing - Oil and Natural Gas
  The
producers of oil are entitled to negotiate sales contracts directly with oil
purchasers, with the result that the market determines the price of
oil.  Oil prices are primarily based on worldwide supply and
demand.  The specific price depends in part on oil quality, prices of
competing fuels, distance to market, the value of refined products, the
supply/demand balance, and other contractual terms.  Oil exporters are
also entitled to enter into export contracts with terms not exceeding one year
in the case of light crude oil and two years in the case of heavy crude oil,
provided that an order approving such export has been obtained from the National
Energy Board of Canada (the "NEB").  Any oil
export to be made pursuant to a contract of longer duration (to a maximum of 25
years) requires an exporter to obtain an export licence from the NEB and the
issuance of such licence requires a public hearing and the approval of the
Governor in Council.
  The price
of natural gas is determined by negotiation between buyers and
sellers.  Natural gas exported from Canada is subject to regulation by
the NEB and the Government of Canada.  Exporters are free to negotiate
prices and other terms with purchasers, provided that the export contracts must
continue to meet certain other criteria prescribed by the NEB and the Government
of Canada.  Natural gas (other than propane, butane and ethane)
exports for a term of less than two years or for a term of two to 20 years (in
quantities of not more than 30,000 m3/day),
must be made pursuant to an NEB order.  Any natural gas export to be
made pursuant to a contract of longer duration (to a maximum of 25 years) or a
larger quantity requires an exporter to obtain an export licence from the NEB
and the issuance of such licence requires a public hearing and the approval of
the Governor in Council.
  The
governments of Alberta, British Columbia, and Saskatchewan also regulate the
volume of natural gas that may be removed from those provinces for consumption
elsewhere based on such factors as reserve availability, transportation
arrangements, and market considerations.
   40
  Pipeline
Capacity
  Although
pipeline expansions are ongoing, the lack of firm pipeline capacity continues to
affect the oil and natural gas industry from time to time by limiting the
ability to produce and to market oil and natural gas production.  In
addition, the pro-rationing of capacity on the inter-provincial pipeline systems
from time to time also continues to affect the ability to export oil and natural
gas.
  The
North American Free Trade Agreement
  The North
American Free Trade Agreement ("NAFTA") among the governments
of Canada, United States of America, and Mexico became effective on January 1,
1994.  NAFTA carries forward most of the material energy terms that
are contained in the Canada United States Free Trade Agreement.  In
the context of energy resources, Canada continues to remain free to determine
whether exports of energy resources to the United States or Mexico will be
allowed, provided that any export restrictions do not: (i) reduce the proportion
of energy resources exported relative to domestic use (based upon the proportion
prevailing in the most recent 36 month period); (ii) impose an export price
higher than the domestic price subject to an exception with respect to certain
voluntary measures which only restrict the volume of exports; and (iii) disrupt
normal channels of supply.  All three countries are prohibited from
imposing minimum or maximum export or import price requirements, provided, in
the case of export price requirements, any prohibition in any circumstances in
which any other form of quantitative restriction is prohibited, and in the case
of import-price requirements, such requirements do not apply with respect to
enforcement of countervailing and anti-dumping orders and
undertakings.
  NAFTA
contemplates the reduction of Mexican restrictive trade practices in the energy
sector by 2010 and prohibits discriminatory border restrictions and export
taxes.  NAFTA also contemplates clearer disciplines on regulators to
ensure fair implementation of any regulatory changes and to minimize disruption
of contractual arrangements and avoid undue interference with pricing, marketing
and distribution arrangements, which is important for Canadian natural gas
exports.
  Provincial
Royalties and Incentives
  General
  In
addition to federal regulation, each province has legislation and regulations
that govern land tenure, royalties, production rates, environmental protection,
and other matters.  The royalty regime is a significant factor in the
profitability of crude oil, natural gas liquids, sulphur, and natural gas
production.  Royalties payable on production from lands other than
Crown lands are determined by negotiation between the mineral freehold owner and
the lessee, although production from such lands is subject to certain provincial
taxes and royalties.  Crown royalties are determined by governmental
regulation and are generally calculated as a percentage of the value of the
gross production.  The rate of royalties payable generally depends in
part on prescribed reference prices, well productivity, geographical location,
field discovery date, method of recovery, and the type or quality of the
petroleum product produced.  Other royalties and royalty-like
interests are, from time to time, carved out of the working interest owner's
interest through non-public transactions.  These are often referred to
as overriding royalties, gross overriding royalties, net profits interests, or
net carried interests.
  Occasionally
the governments of the western Canadian provinces create incentive programs for
exploration and development.  Such programs often provide for royalty
rate reductions, royalty holidays, and tax credits, and are generally introduced
when commodity prices are low.  The programs are designed to encourage
exploration and development activity by improving earnings and cash flow within
the industry.  Royalty holidays and reductions would reduce the amount
of Crown royalties paid by oil and gas producers to the provincial governments
and would increase the net income and funds from operations of such
producers.  However, the trend in recent years, in light of high
commodity prices, has been for provincial governments to eliminate, amend or
allow such incentive programs to expire without renewal.Recent actions taken by
provincial governments (and in particular the Alberta government) in response to
the quick and significant decrease in commodity prices signal that this trend
has slowed and may be changing course (at least temporarily until commodity
prices recover).  See below for further details.
  The
Canadian federal corporate income tax rate levied on taxable income is 19.5%
effective January 1, 2008 for active business income including resource
income.  With the elimination of the corporate surtax effective
January 1, 2008 and other rate reductions introduced in the October 2007
Economic Statement and Notice of Ways and Means Motion, 2006
Federal
   41
  Budget,
the federal corporate income tax rate will decrease to 15% in four additional
steps: 19% on January 1, 2009; 18% on January 1, 2010; 16.5% on January 1, 2011;
and 15% on January 1, 2012.
  Alberta
  In
Alberta, companies are granted the right to explore, produce and develop
petroleum and natural gas resources in exchange for royalties, bonus bid
payments and rents.  On October 25, 2007, the Government of Alberta
released a report entitled "The New Royalty Framework" (the "NRF") containing the
Government's proposals for Alberta's new royalty regime, which was followed by
the Mines and Minerals (New Royalty Framework) Amendment Act, 2008, which was
given Royal Assent on December 2, 2008.  The NRF and the applicable
new legislation became effective on January 1, 2009.  Prior to the
NRF, the amount of royalties that were payable was influenced by the oil
production, density of the oil, and the vintage of the
oil.  Originally, the vintage classified oil was "new oil" and "old
oil" depending on when the oil pools were discovered.  If the pool was
discovered prior to March 31, 1974 it was considered "old oil", if it was
discovered after March 31, 1974 and before September 1, 1992, it was considered
"new oil".  The Alberta Government introduced in 1992 a Third Tier
Royalty with a base rate of 10% and a rate cap of 25% for oil pools discovered
after September 1, 1992.  The new oil royalty reserved to the Crown
had a base rate of 10% and a rate cap of 30%.  The old oil royalty
reserved to the Crown had a base rate of 10% and a rate cap of
35%.  The NRF eliminates this classification and establishes new
royalty rates for conventional oil, natural gas and oil sands.  The
new royalty rates for conventional oil are set by a single sliding rate formula
which is applied monthly and increases the old royalty from 30% to 35% applied
to the old and new tiers, to up to 50% and with rate caps once the price of
conventional oil reaches $120 per barrel.  The sliding rate formula
includes in its calculation the price of oil and well production.
  With
respect to natural gas, and similar to the conventional oil framework, the
royalties outlined in the NRF are set by a single sliding rate formula ranging
from 5% to 50% with a rate cap once the price of natural gas reaches
$16.59/GJ.  Prior to the NRF, the royalty reserved to the Crown in
respect of natural gas production, subject to various incentives, was between
15% and 30%, in the case of new natural gas, and between 15% and 35%, in the
case of old natural gas, depending upon a prescribed or corporate average
reference price.  In response to the drop in commodity prices
experienced during the second half of 2008, the Government of Alberta announced
on November 19, 2008, the introduction of a five year program of
transitional royalty rates with the intent of promoting new
drilling.  Under this new program companies drilling new natural gas
or conventional oil deep wells (between 1,000 and 3,500 metres) will be given a
one-time option, on a well by well basis, to adopt either the new transitional
royalty rates or those outlined in the NRF.  In order to qualify for
this program wells must be drilled during the period starting on
November 19, 2008 and ending on December 31,
2013.  Following this period all new wells drilled will automatically
be subject to the NRF.
  Oil sands
projects are now subject to the NRF and are regulated by, among others, the
Oil Sands Royalty Regulation,
2009 Oil Sands Allowed Costs (Ministerial) Regulation and the Bitumen Valuation Methodology
(Ministerial) Regulation, 2009, all approvedby the Government of
Alberta on December 10, 2008.  The rates applicable to oil sands are
between 1% and 9% and are calculated depending on the price of
oil.  The royalty payable is 1% when oil is priced below or at $55 per
barrel and it increases for every dollar over and above that price, to a maximum
of 9% when oil is priced at $120 or higher.  The after payout net
royalty starts at 25% and increases for every dollar when oil is priced above
$55 up to 40% when oil is priced at $120 or higher.
  On April
10, 2008, the Government of Alberta introduced two new royalty programs that
will encourage the development of deep oil and gas reserves: (a) a five-year oil
program for exploration wells over 2,000 metres that will provide royalty
adjustments to offset higher drilling costs and provide a greater incentive for
producers to continue to pursue new, deeper oil plays (these oil wells will
qualify for up to a $1 million or 12 months of royalty offsets, whichever comes
first); and (b) a five-year natural gas deep drilling program that will replace
the existing program in order to encourage continued deep gas exploration for
wells deeper than 2,500 metres (the program will create a sliding scale of
royalty credit according to depth, of up to $3,750 per metre).  These
new programs are being implemented along with the NRF.
  Regulations
made pursuant to the Mines and
Minerals Act (Alberta) provided various incentives for exploring and
developing oil reserves in Alberta.  However, the Alberta Government
announced in August of 2006 that four royalty programs were to be amended, a new
program was to be introduced and the Alberta Royalty Tax Credit Program was to
be eliminated, effective January 1, 2007.  The programs affected by
this announcement were: (i) Deep Gas Royalty Holiday; (ii) Low Productivity Well
Royalty Reduction; (iii) Reactivated Well Royalty Exemption; and (iv) Horizontal
Re-Entry Royalty Reduction.  The program introduced was the Innovative
Energy Technologies Program (the "IETP"), which has a
stated
   42
  objective
of promoting the producers' investment in research, technology and innovation
for the purposes of improving environmental performance while creating
commercial value.  The IETP provides royalty reductions that are
presumed to reduce financial risk.  Alberta Energy decides which
projects qualify and the level of support that will be provided.  The
deadline for the IETP's final round of applications was September 20,
2008.  The successful applicants for the first two rounds have been
announced, and those for the third round selection are scheduled to be announced
in the first half of 2009.  The technical information gathered from
this program is to be made public once a two-year confidentiality period
expires.
  The NRF
includes a policy of "shallow rights reversion".  The Government of
Alberta started to implement this policy on January 1, 2009, and its intent is
to maximize the development of currently undeveloped resources that is
consistent with the Government of Alberta's objective of maximizing recovery of
known gas resources, while increasing royalty revenues.  The policy's
stated objective is for the mineral rights to shallow gas geological formations
that are not being developed to revert back to the Government and be made
available for resale, and in the event of non-productive shallow wells, to sever
the rights from shallow zones and encourage increased production from up-hole
zones.  The shallow rights reversion policy affects all petroleum and
natural gas agreements; however, the timing of the reversion will differ
depending on whether the leases and licenses were acquired prior to January 1,
2009 or subsequent to January 1, 2009.  Leases granted after January
1, 2009 will be subject to shallow rights reversion at the expiry of the primary
term, and in the event of a licence the policy will apply at the expiry of the
intermediate term.  Holders of leases or licences that have been
continued indefinitely prior to January 1, 2009 will receive a notice regarding
the reversion of the shallow rights, which will be implemented three years from
the date of the notice.  The lease or licence holder can make a
request to extend this period.  The order in which these agreements
will receive the reversion notice will depend on the vintage of their term, with
the older leases and licenses receiving a reversion notice
first.  Leases or licences that were granted prior to January 1, 2009
but have not yet been continued will have a grace period until they are
continued under section 15 of the P&G Tenure Regulation and
will be subject to deeper rights reversion prior to receiving a shallow rights
reversion notice.
  On March
3, 2009, the Government of Alberta announced a three-point incentive program to
stimulate new and continued economic activity in Alberta.  The program
includes a drilling royalty credit for new conventional oil and natural gas
wells and a new well royalty incentive program.  Under the drilling
royalty credit program a $200 per meter royalty credit will be available on new
conventional oil and natural gas wells drilled between April 1, 2009 and March
31, 2010, subject to certain maximum amounts.  The maximum credits
available will be determined by a company's production level in 2008 and its
drilling activity between April 1, 2009 and March 31, 2010.  Based on
our 2008 production we will be entitled to a maximum credit of approximately $30
million of royalties payable during the period of April 1, 2009 to March 31,
2010.  The new well royalty incentive program will apply to wells that
commence production of conventional oil and natural gas between April 1, 2009
and March 31, 2010.  The program provides for a maximum 5% royalty
rate for the first 12 months of production, up to a maximum of 50,000 barrels of
oil or 500 MMcf of natural gas.
  The
three-point incentive program also includes an investment of $30 million by the
Government of Alberta in abandonment and reclamation projects for orphan
wells.  The stated objective of this investment is to encourage the
cleanup of inactive oil and gas wells and to stimulate new activity within the
services sector.
  British
Columbia
  Producers
of oil and natural gas in British Columbia are required to pay annual rental
payments with respect to the Crown leases and royalties and freehold production
taxes in respect of oil and gas produced from Crown and freehold
lands.  The amount payable as a royalty in respect of oil depends on
the type of oil, the value of the oil, the quantity of oil produced in a month,
and the vintage of the oil.  Generally, the vintage of oil is based on
the determination of whether the oil is produced from a pool discovered before
October 31, 1975 (old oil), between October 31, 1975 and June 1, 1998 (new oil),
or after June 1, 1998 (third-tier oil).  The royalty rates are
calculated in three stages, which take into account the vintage of the oil, if
the oil produced has already been sold and any royalty exempt value applicable
(exempt wells).  Oil produced from newly discovered pools may be
exempt from the payment of a royalty for the first 36 months of production or
11,450m3
produced, whichever comes first; and the royalties for third-tier oil are the
lowest reflecting the higher costs of exploration and extraction that the
producers incur.  The royalty payable on natural gas is determined by
a sliding scale based on a reference price, which is the greater of the price
obtained by the producer, and a prescribed minimum price.  However,
when the reference price is below the select price (a parameter used in the
royalty rate formula), the royalty rate is fixed.  As an incentive for
the production and marketing of natural gas, which may have been flared, natural
gas produced in association with oil has a lower royalty than the royalty
payable on non-conservation gas.
  43
  On May
30, 2003, the Ministry of Energy and Mines for British Columbia announced an Oil
and Gas Development Strategy for the Heartlands ("Strategy").  The
Strategy is a comprehensive program to address road infrastructure, targeted
royalties and regulatory reduction, and British Columbia service sector
opportunities.  In addition, the Strategy is intended to result in
economic and employment opportunities for communities in British Columbia's
heartlands.
  Some of
the financial incentives in the Strategy include:
  ·
              Royalty
      credits towards the construction, upgrading, and maintenance of road
      infrastructure in support of resource exploration and
      development.  Funding will be contingent upon an equal
      contribution from industry.  This program has evolved over past
      years as a result of the Province's stated objective to increase
      competitiveness.  On March 2, 2009, the Government of British
      Columbia announced the 2009 Infrastructure Royalty Credit Program ("Program"), which
      allocates $120 million in royalty credits for oil and gas
      companies.  The Program provides access to royalty credits to
      oil and gas companies with respect to certain approved road construction
      or pipeline infrastructure projects intended to improve, or make possible,
      the access to new and underdeveloped oil and gas
      areas.  Companies must apply to the Ministry of Energy and Mines
      for British Columbia prior to 2:00 p.m. on April 30, 2009 to be
      considered for approval under the
program.
  ·
              Changes
      to provincial royalties: new royalty rates for low productivity natural
      gas to enhance marginally economic resources plays, royalty credits for
      deep gas exploration to locate new sources of natural gas, and royalty
      credits for summer drilling to expand the drilling
  season.
  The
British Columbia Energy Plan announced on February 27, 2007 outlines the
requirements for the development of goals for conservation, energy efficiency
and clean energy.  In addition, its stated goals include to promote
competitiveness through the implementation of a Net Profit Royalty Program
("NPRP") and facilitate
the development of the oil and gas industry.  The NPRP's objective is
to share the capital risk of successful developments.  Pursuant to the
Net Profit Royalty Regulation, the holder of a lease can apply to pay monthly
net profit royalties on production of oil and for natural gas wells within a
proposed project.  The amount paid is calculated on the producer's
interest in the project, and it ranges from 2% to 5% of the gross revenue and
15% to 35% of the net revenues received.  In addition, it depends on
which stage the well is at, which may be either pre-payout, after-payout or
already producing marketable gas.
  The
Government of British Columbia has introduced a few more royalty programs, in
addition to the ones previously mentioned, including a royalty program for deep
discovery wells, royalty programs with a stated goal of attracting investment to
less productive shallow gas wells (Ultra-Marginal Royalty Program), and the
implementation of royalty credits to assist the development of the coal-bed gas
reserves found in the Province of British Columbia.
  Saskatchewan
  In
Saskatchewan, the amount payable as a royalty in respect of oil depends on the
vintage of the oil, the type of oil, the quantity of oil produced in a month,
and the value of the oil.  For Crown royalty and freehold production
tax purposes, crude oil is considered "heavy oil", "southwest designated oil",
or "non-heavy oil other than southwest designated oil".  The
conventional royalty and production tax classifications of oil production are
applicable to each of the three crude oil types.  The Crown royalty
and freehold production tax structure for crude oil is price sensitive and
varies between the base royalty rates of 5% for all "fourth tier oil" to 20% for
"old oil".  Marginal royalty rates are 30% for all "fourth tier oil"
to 45% for "old oil".
  The
amount payable as a royalty in respect of natural gas is determined by a sliding
scale based on a reference price (which is the greater of the amount obtained by
the producer and a prescribed minimum price), the quantity produced in a given
month, the type of natural gas, and the vintage of the natural
gas.  As an incentive for the production and marketing of natural gas
which may have been flared, the royalty rate on natural gas produced in
association with oil is less than on non-associated natural gas.  The
royalty and production tax classifications of gas production are "fourth tier
gas" introduced October 1, 2002, "third tier gas", "new gas", and "old
gas".  The Crown royalty and freehold production tax for gas is price
sensitive and varies between the base royalty rate of 5% for "fourth tier gas"
and 20% for "old gas".  The marginal royalty rates are between 30% for
"fourth tier gas" and 45% for "old gas".
  On
October 1, 2002, the following changes were made to the royalty and tax regime
in Saskatchewan:
   44
  ·
              A
      new Crown royalty and freehold production tax regime applicable to
      associated natural gas (gas produced from oil wells) that is gathered for
      use or sale and is produced from: (a) oil wells with a finished drilling
      date on or after October 1, 2002; and (b) oil wells with a finished
      drilling date prior to October 1, 2002, where the individual oil well has
      a gas-oil production ratio in any month of more than 3,500 cubic metres of
      gas for every cubic metre of oil.  The royalty/tax is payable on
      associated natural gas produced from an oil well that exceeds
      approximately 65,000 cubic metres in a month.  The associated
      natural gas royalty/tax regime will apply to gas produced from oil wells
      affected by concurrent production approvals after October 1, 2002 if the
      oil wells meet the criteria in paragraphs (a) or (b)
  above.
  ·
              A
      modified system of incentive volumes and maximum royalty/tax rates
      applicable to the initial production from oil wells and gas wells with a
      finished drilling date on or after October 1, 2002 was
      introduced.  The incentive volumes are applicable to various
      well types and are subject to a maximum royalty rate of 2.5% and a
      freehold production tax rate of zero
percent.
  ·
              The
      elimination of the re-entry and short section horizontal oil well
      royalty/tax categories.  All horizontal oil wells with a
      finished drilling date on or after October 1, 2002 will receive the
      "fourth tier" royalty/ tax rates and new incentive
  volumes.
  ·
              A
      horizontal oil well with a finished drilling date on or after October 1,
      2002 that is a non-deep oil well qualifies for a 6,000 cubic metre
      incentive volume.
  ·
              A
      horizontal oil well with a finished drilling date on or after October 1,
      2002 that is a deep oil well qualifies for a 16,000 cubic metre incentive
      volume.
  In 1975,
the Government of Saskatchewan introduced a Royalty Tax Rebate ("RTR") as a response to the
Government of Canada disallowing crown royalties and similar taxes as a
deductible business expense for income tax purposes.  As of January 1,
2007, the remaining balance of any unused RTR will be limited in its carry
forward to seven years since the Government of Canada's initiative to
reintroduce the full deduction of provincial resource royalties from federal and
provincial taxable income.  Saskatchewan's RTR will be wound down as a
result of the Government of Canada's plan to reintroduce full deductibility of
provincial resource royalties for corporate income tax purposes.
  On June
19, 2007, the Government of Saskatchewan introduced the Orphan Well and Facility
Liability Management Program pursuant to the amendment of the Oil and Gas Conservation Act
and the Oil and Gas
Conservation Regulations, 1985.  The program includes a
security deposit, which has two purposes: (i) preventing any person with
insufficient financial capability from acquiring oil and gas wells or
facilities; and (ii) in the case of a bankrupt company, the funds cover the
decommissioning and reclaiming of orphan properties.  An additional
change introduced is the mandatory licensing of all upstream oil and gas
facilities in Saskatchewan.
  Land
Tenure
  Crude oil
and natural gas located in the western provinces is owned predominantly by the
respective provincial governments.  Provincial governments grant
rights to explore for and produce oil and natural gas pursuant to leases,
licences, and permits for varying terms, the minimum of which is two years, and
on conditions set forth in provincial legislation including requirements to
perform specific work or make payments.  Oil and natural gas located
in such provinces can also be privately owned and rights to explore for and
produce such oil and natural gas are granted by lease on such terms and
conditions as may be negotiated.
  Environmental
Regulation
  The oil
and natural gas industry is subject to environmental regulations pursuant to a
variety of provincial and federal legislation.  Such legislation
provides for restrictions and prohibitions on the release or emission of various
substances produced in association with certain oil and gas industry
operations.  In addition, such legislation requires that well and
facility sites be abandoned and reclaimed to the satisfaction of provincial
authorities.  Compliance with such legislation can require significant
expenditures and a breach of such requirements may result in suspension or
revocation of necessary licenses and authorizations, civil liability for
pollution damage, and the imposition of material fines and
penalties.
   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").  The EPEA
and OGCA impose stricter environmental standards, require more stringent
compliance, reporting and monitoring obligations, and significantly increased
penalties.  In 2006, the Alberta Government enacted regulations
pursuant to the EPEA to specifically target sulphur oxide and nitrous oxide
emissions from industrial operations including the oil and gas
industry.  In addition, the reduction emission guidelines outlined in
the Climate Change and
Emissions Management Amendment Actcame into effect on July 1, 2007
("CCEMAA").  Under
this legislation, Alberta facilities emitting more than 100,000 tonnes of
greenhouse gases a year must reduce their emissions intensity by
12%.  Industries have three options to choose from in order to meet
the reduction requirements outlined in this legislation: (i) by making
improvements to operations that result in reductions; (ii) by purchasing
emission credits from other sectors or facilities that have emissions below the
100,000 tonne threshold and are voluntarily reducing their emission; or (iii) by
contributing to the Climate Change and Emissions Management Fund (the "Fund").  Industries
can either choose one of these options or a combination
thereof.  Pursuant to CCEMAA and the Specified Gas Emitters
Regulation, companies were obliged to reduce their emission intensity by
12% by March 31, 2008.  Alberta industries have achieved 2.6 million
tonnes of actual reduction, due to changes in operations and investing on
verified offset projects.  In addition, certain companies contributed
$40 million to the Fund.  It is reasonably likely that the trend
towards stricter standards in environmental legislation and regulation will
continue.
  On
January 24, 2008, the Alberta Government announced a new climate change action
plan that will cut Alberta's projected 400 million tonnes of emissions in half
by 2050.  This plan focuses on three areas: (i) carbon capture and
storage, which will be mandatory for in situ oil sand facilities
that use heavy fuels for steam generation; (ii) energy conservation and
efficiency; and (iii) greening production through increased investment in clean
energy technology, including supporting research on new oil sands extraction
processes and funding projects that reduce the cost of separating carbon dioxide
from other emissions.  In addition to this action plan, the Provincial
Energy Strategy unveiled on December 11, 2008 is expected to, among other
things, support the upgrading, refining and petrochemical clusters existing in
the Province, market Alberta's energy internationally, review the emission
targets and carbon charges applied to large facilities, and promote the
innovation of energy technology by encouraging investment in research and
development.
  British
Columbia
  British
Columbia's Environmental Assessment Act became effective on June 30,
1995.  This legislation rolls the previous processes for the review of
major energy projects into a single environmental assessment process with public
participation in the environmental review process.  On February 27,
2007, the Government of British Columbia unveiled the Energy Plan outlining its
strategy towards the environment, which includes targeting zero net greenhouse
gas emissions, promoting new investments in innovation, and becoming the world's
leader in sustainable environmental management.  For this purpose, on
December 18, 2007 proposals were sought for applications to the Innovative Clean
Energy Fund, in order to attract new technologies that will help solve energy
and environmental issues.  With regards to the oil and natural gas
industry the objective is to achieve clean energy through conservation and
energy efficient practices, while competitiveness is advocated in order to
attract investment for the development of the oil and natural gas
sector.  Among the changes to be implemented are: (i) a new Net Profit
Royalty Program; (ii) the creation of a Petroleum Registry; (iii) the
establishment of an infrastructure royalty program (combining roads and
pipelines); (iv) the elimination of routine flaring at producing wells; (v) the
creation of policies and measures for the reduction of emissions; (vi) the
development of unconventional resources such as tight gas and coalbed gas; and
(vii) the new Oil and Gas Technology Transfer Incentive Program that encourages
the research, development and use of innovative technologies to increase
recoveries from existing reserves and promotes responsible development of new
oil and gas reserves.  In furtherance of these initiatives, on July 1,
2008 the Government of British Columbia introduced revenue-neutral carbon tax
legislation that is applied to all fossil fuels used in the Province of British
Columbia.  The tax would be phased in, and the initial rate would be
based on CO2 equivalent of $10 per tonne for the first six months of 2009 and
$15 per tonne for the last six months of 2009, followed by $5 per tonne
increases in Julyof every year until
2012.  Tax credits and reductions will be used in order to offset the
tax revenues that the Government of British Columbia would receive
otherwise.  On April 3, 2008, the Government of British Columbia
introduced the Greenhouse Gas
Reduction (Cap and Trade) Act, which will allow participation in the
Western Climate Initiative cap and trade system that is currently being
developed.  The system establishes a limit on emissions and allows
regulated emitters to buy/sell emission allowances or offset
emits.  The emitter is obliged to obtain emission allowances
(compliance units) equal to the amount of
   46
  greenhouse
gases emitted within a certain period of time, and that are supposed to be
surrendered to the Government of British Columbia as proof of
compliance.
  Federal
  In
December 2002, the Government of Canada ratified the Kyoto Protocol ("Kyoto
Protocol").  The Kyoto Protocol calls for Canada to reduce its
greenhouse gas emissions to 6% below 1990 "business-as-usual" levels between
2008 and 2012.  Given revised estimates of Canada's normal emissions
levels, this target translates into an approximately 40% gross reduction in
Canada's current emissions.  It is uncertain, based on the Updated
Action Plan announced by the Federal Government (see below), that the Kyoto
Protocol target of 6% below 1990 emission levels will be enforced in
Canada.  Bill C-288, which is intended to ensure that Canada meets its
global climate change obligations under the Kyoto Protocol, was passed by the
House of Commons on February 14, 2007.  On April 26, 2007, the Federal
Government released its Action Plan to Reduce Greenhouse Gases and Air Pollution
(the "Action Plan")
(also known as ecoACTION), which includes the regulatory framework for air
emissions.  This Action Plan covers not only large industry, but
regulates the fuel efficiency of vehicles and the strengthening of energy
standards for a number of energy using products.
  On
January 31, 2008, the Government of Canada and the Province of Alberta released
the final report of the Canada-Alberta ecoENERGY Carbon Capture and Storage Task
Force, which recommends, among others things: (i) incorporating carbon capture
and storage into Canada's clean air regulations; (ii) allocating new funding
into projects through competitive process; and (iii) targeting research to lower
the cost of technology.
  In order
to strengthen the Action Plan, on March 10, 2008, the Government of Canada
released "Turning the Corner – Taking Action to Fight Climate Change" (the
"Updated Action Plan"),
which provides some additional guidance with respect to the Government's plan to
reduce greenhouse gas emissions by 20% by 2020 and by 60% to 70% by
2050.
  The
Updated Action Plan is primarily directed towards industrial emissions from
certain specified industries, including the oil sands, oil and gas and
refining.  The Updated Action Plan is intended to create a carbon
emissions trading market, including an offset system, to provide an incentive to
reduce greenhouse gas emissions and establish a market price for
carbon.  There are mandatory reductions of 18% from the 2006 baseline
starting in 2010 and an additional 2% in subsequent years for existing
facilities.  This target will be applied to regulated sectors on a
facility-specific, sector-wide or corporate basis.  In the case of oil
sands production, petroleum refining, natural gas pipelines and upstream oil and
gas the target will be considered facility-specific (sectors in which the
facilities are complex and diverse, or where emissions are affected by factors
beyond the control of the facility operator).  Emissions from new
facilities, which are those built between 2004 and 2011, will be based on a
cleaner fuel standard to encourage continuous emissions intensity reductions
over time, and will be granted a 3-year grace period during which no emissions
intensity targets will apply.  Targets will begin to apply on the
fourth year of commercial operation and the baseline will be the third year's
emissions intensity, with a 2% continuous annual emission intensity improvement
required.  The definition of new facility also includes greenfield
facilities, major expansions constituting more than a 25% increase in a
facility's physical capacity, as well as transformations to a facility that
involve significant changes to its processes.  For upstream oil and
gas and natural gas pipelines, it will be applied using a sector-specific
approach.  For the oil sands, its application will be
process-specific: oil sands plants built in 2012 and later, those which use
heavier hydrocarbons, up-graders and in-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 respect of the above targets:
Technology Fund contributions, offset credits, clean development credits and
credits for early action.  The most significant of these compliance
mechanisms, at least initially, will be the Technology Fund, to which regulated
entities will be able to contribute in order to comply with emissions intensity
reductions.  The contribution rate will increase over time, beginning
at $15 per tonne for the 2010 to 2012 period, rising to $20 per tonne in 2013,
and thereafter increasing at the nominal rate of gross domestic product
growth.  Contribution limits will correspondingly decline from 70% in
2010 to 0% in 2018.  Monies raised through contributions to the
Technology Fund will be used to invest in technology to reduce greenhouse gas
emissions.  Alternatively, regulated entities may be able
   47
  to
receive credits for investing in large-scale and transformative projects at the
same contribution rate and under similar requirements as mentioned
above.
  The
offset system is intended to encourage emissions reductions from activities
outside of the regulated sphere, allowing non-regulated entities to participate
in and benefit from emissions reduction activities.  In order to
generate offset credits, project proponents must propose and receive approval
for emissions reduction activities that will be verified before offset credits
will be issued to the project proponent.  Those credits can then be
sold to regulated entities for use in compliance or non-regulated purchasers
that wish to either cancel the offset credits or bank them for future use or
sale.
  Under the
Updated Action Plan, regulated entities will also be able to purchase credits
created through the Clean Development Mechanism of the Kyoto
Protocol.  The purchase of such emissions reduction credits will be
restricted to 10% of each firm's regulatory obligation, with the added
restriction that credits generated through forest sink projects will not be
available for use in complying with the Canadian regulations.
  Finally,
a one-time credit of up to 15 metric tons worth of emissions credits will be
awarded to regulated entities for emissions reduction activities undertaken
between 1992 and 2006.  These credits will be both tradable and
bankable.
  Penn
West and the Environment
  We
understand our responsibilities of reducing the environmental impacts from our
operations and recognize the interests of other land users in resource
development areas, and conduct our operations accordingly.  We are
committed to reducing the environmental impact from our operations, and to
involving stakeholders throughout the exploration, development, production and
abandonment process. Our environmental programs encompass resource conservation,
stakeholder communication and site abandonment/reclamation.  Our
environmental programs are monitored to ensure that they comply with all
government environmental regulations and with our own environmental policies.
The results of these programs are reviewed with our management and operations
personnel.
  Our
Environmental Policy and Environmental Management Plan ("EMP") encompass the full range
of air, water, soil and waste issues associated with exploration, development
and production. The EMP includes guidelines to 11 key areas that are considered
in conjunction with oil and natural gas development plans. These guidelines help
ensure safe and environmentally sound field operations. The Environmental
Operating Guidelines are used to train our employees in the practical and
economic implementation of the EMP.
  We
maintain a program of detailed inspections, audits and field assessments to
determine and quantify the environmental liabilities that will be incurred
during the eventual decommissioning and reclamation of our field facilities. We
pursue a program of environmental impact reduction aimed at minimizing these
future corporate liabilities without hampering field productivity. This program,
launched in 1994and ongoing into 2009,
includes measures to remediate potential contaminant sources, reclaim spill
sites and abandon unproductive wells and shut-in facilities. We have implemented
strategies to reduce greenhouse gas emissions and flaring and continued the
program to test 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 green
house gas (GHG) emissions.  However, we do have minor working
interests in five non-operated facilities that were required to meet the Alberta
regulations.  All of our fuel use in British Columbia is subject to a
carbon tax based on consumption.  The financial obligation, in both
Alberta and British Columbia, is not material at this time.
  Because
the federal and provincial programs relating to the regulation of the emission
of greenhouse gases and other air pollutants continue to be developed, we are
currently unable to predict the total impact of the potential regulations upon
our business. Therefore, it is possible that we could face increases in
operating costs in order to comply with emissions legislation. However, in
cooperation with the Canadian Association of Petroleum Producers, we will
continue to work cooperatively with governments to develop an approach to deal
with climate change issues that protects the industry's competitiveness, limits
the cost and administrative burden of compliance and supports continued
investment in the sector.  In the meantime, we will continue our
current activities to reduce our emissions intensity, improve energy efficiency
and develop CO2 injection
and sequestration infrastructure.
   48
  Penn West
provides additional information on greenhouse gases on our website and also
participates in the annual international Carbon Disclosure
Project.  These two sources detail significantly more information
regarding emissions, business strategy, governance, and potential risks for
those who are interested.
  During
2008, we continued our pilot-scale CO2injection
program in the Pembina area and initiated a new CO2 injection
pilot in the Swan Hills area.  If successful, the pilots could lead to
a much larger enhanced oil recovery program with potential to sequester
significant volumes of CO2. Also in
2008, we continued to participate in studies to develop a cost effective system
to source large volumes of CO2currently
emitted within Alberta, and to transport it by pipeline for injection into
producing oil fields in central Alberta.
  We are
committed to meeting our responsibilities to protect the environment wherever we
operate and we anticipate making increased expenditures of both a capital and an
expense nature as a result of the increasingly stringent laws relating to the
protection of the environment.  We will be taking such steps as
required to ensure continued compliance with applicable environmental
legislation in each jurisdiction in which we operate.  We believe that
we are currently in material compliance with applicable environmental laws and
regulations.  We also believe that it is reasonably likely that the
trend towards stricter standards in environmental legislation and regulation
will continue.
  
  RISK FACTORS
  The
following is a summary of certain risk factors relating to the business of Penn
West and the Operating Entities.  The following information is a
summary only of certain risk factors and is qualified in its entirety by
reference to, and must be read in conjunction with, the detailed information
appearing elsewhere in this Annual Information Form.  Unitholders and
potential Unitholders should consider carefully the information contained herein
and, in particular, the following risk factors.  If any of these risks
occur, our production, revenues and financial condition could be materially
harmed, with a resulting decrease in distributions on, and the market price of,
our Trust Units.
  Volatility
in oil and natural gas prices could have a material adverse effect on our
results of operations and financial condition, which in turn could negatively
affect the amount of distributions paid to our Unitholders.
  Our
results of operations and financial condition are dependent upon the prices that
we receive for the oil and natural gas that we sell.  Historically,
the oil and natural gas markets have been volatile and are likely to continue to
be volatile in the future.  Oil and natural gas prices have fluctuated
widely during recent years and are subject to fluctuations in response to
relatively minor changes in supply, demand, market uncertainty and other factors
that are beyond our control.  These factors include, but are not
limited to:
  ·
              global
      energy policy, including the ability of OPEC to set and maintain
      production levels and influence prices for
oil;
 ·
              political
      instability and hostilities and the risk of
  hostilities;
 ·
              foreign
      supply of oil and natural gas, including liquefied natural
      gas;
 ·
              weather
      conditions;
 ·
              the
      overall level of energy demand;
 ·
              production
      and storage levels of natural gas;
 ·
              government
      regulations and taxes;
 ·
              currency
      exchange rates;
 ·
              the
      availability of transportation
infrastructure;
 ·
              the
      effect of worldwide environmental and/or energy conservation
      measures;
 ·
              the
      price and availability of alternative energy supplies;
  and
 ·
              the
      overall economic environment.
  Any
decline in the price of oil or natural gas could have a material adverse effect
on our operations, financial condition, borrowing ability, reserves and the
level of expenditures for the development of reserves.  Fluctuations
in the price of oil and natural gas will also have an effect on the acquisition
costs of any future oil and natural gas properties that we may
acquire.  In addition, cash distributions paid to Unitholders are
highly sensitive to the prevailing price of crude oil and natural gas and may
decline with any decline in the price of oil or natural gas.
   49
  The
price of oil and natural gas is affected by political events throughout the
world.  Any such event could result in a material decline in prices
and result in a reduction of the funds flow available for distribution to
Unitholders.
  The
marketability and price of oil and natural gas that may be acquired or
discovered by us is and will continue to be affected by political events
throughout the world that cause disruptions in the supply of
oil.  Conflicts, or conversely peaceful developments, arising in the
Middle East, and other areas of the world, have a significant impact on the
price of oil and natural gas.  Any particular event could result in a
material decline in prices and therefore result in a reduction of our revenue
and consequently the funds flow available for distribution to
Unitholders.
  In
addition, our oil and natural gas properties, wells and facilities could be
subject to a terrorist attack.  If any of our properties, wells or
facilities are the subject of a terrorist attack it could have a material
adverse effect on us.  We do not currently have insurance in respect
of our Canadian operations to protect against the risk of
terrorism.
  The
ongoing global financial crisis has had (and may continue to have) an adverse
effect on commodity prices and has had (and may continue to have) an adverse
effect on our access to capital, one or both of which could have a material
adverse effect on our results of operations and financial condition, which in
turn could negatively affect the amount of distributions paid to our
Unitholders.
  Recent
market events and conditions, including disruptions in the international credit
markets and other financial systems and the deterioration of global economic
conditions, have caused significant volatility to commodity
prices.  These conditions worsened in 2008 and are continuing in 2009,
causing a loss of confidence in the broader U.S. and global credit and financial
markets and resulting in the collapse of, and government intervention in, major
banks, financial institutions and insurers and creating a climate of greater
volatility, less liquidity, widening of credit spreads, a lack of price
transparency, increased credit losses and tighter credit
conditions.  Notwithstanding various actions taken by governments,
concerns about the general condition of the capital markets, financial
instruments, banks, investment banks, insurers and other financial institutions
caused the broader credit markets to further deteriorate and stock markets to
decline substantially.  These factors have negatively impacted company
valuations and are expected to impact the performance of the global economy
going forward.
  Petroleum
prices are expected to remain volatile for the near future as a result of market
uncertainties over the supply and demand of these commodities due to the current
state of the world economies, OPEC actions and the ongoing global credit and
liquidity concerns.
  As a
result of the weakened global economic situation, we (and all other oil and gas
entities) expect to have restricted access to capital and increased borrowing
costs for the foreseeable future.  Although our business and asset
base have not changed materially, the lending capacity of all financial
institutions has diminished and risk premiums have increased.  As
future capital expenditures will be financed out of cash generated from
operations, borrowings and possible future equity sales, our ability to do so is
dependent on, among other factors, the overall state of capital markets and
investor appetite for investments in the energy industry and our securities in
particular.
  To the
extent that external sources of capital become limited or unavailable or
available on onerous terms, our ability to make capital investments and maintain
existing assets may be impaired, and our assets, liabilities, business,
financial condition, results of operations and distributions may be materially
and adversely affected as a result.
  At
December 31, 2008, we had approximately $1.4 billion of unused credit
available under our credit facilities.  Based on current funds
available and expected cash from operations, we believe that we have sufficient
funds available to fund our projected capital expenditures.  However,
if cash flow from operations is lower than expected or capital costs for these
projects exceeds current estimates, or if we incur major unanticipated expenses
related to development or maintenance of our existing properties, we may be
required to seek additional capital to maintain our capital expenditures at
planned levels.  Failure to obtain any financing necessary for our
capital expenditure plans may result in a delay in development or production on
our properties and/or a decrease in distributions.
   50
  We
may not be able to repay all or part of our indebtedness, or alternatively
refinance all or part of our indebtedness on commercially reasonable
terms.  We may not be able to comply with the covenants (and in
particular the financial covenants) contained in our debt
instruments.  The occurrence of any one of these events could have a
material adverse effect on our results of operations and financial condition,
which in turn could negatively affect the amount of distributions paid to our
Unitholders.
  We
currently have credit facilities in place that have an aggregate borrowing limit
of $4.0 billion and a maturity date of January 11, 2011.  As of
December 31, 2008, approximately $2.6 billion was outstanding under
our credit facilities.  The credit facilities are comprised of two
tranches which each revolve until their respective maturity
dates.  Tranche one of our credit facilities has an aggregate
borrowing limit of $3.25 billion and is extendible with lender
approval.  We have the right to request an extension of the maturity
date under tranche one such that the term to maturity does not exceed three
years.Tranche two
of our credit facilities has an aggregate borrowing limit of $750 million and is
non-extendible.  In the event that tranche one of our credit
facilities is not extended before January 11, 2011, all outstanding indebtedness
under our credit facilities will be repayable at that date.  There is
also a risk that our credit facilities will not be renewed for the same
principal amount or on the same terms.  Any of these events could
adversely affect our ability to fund our ongoing operations and, as repayment of
such indebtedness has priority over the payment of cash distributions to
Unitholders, to distribute cash to Unitholders.
  We also
currently have: (i) U.S.$475 million principal amount of 2007 Senior Notes
outstanding which require principal repayments starting in May 2015 and
continuing until May 2022; (ii) U.S.$480 million and Cdn$30 million principal
amount of 2008 Senior Notes outstanding which require principal repayments
starting in May 2016 and continuing until May 2020; (iii) £57 million principal
amount of 2008 Pounds Sterling Senior Notes outstanding which require principal
repayment in July 2018; and (iv) $296 million principal amount of Convertible
Debentures outstanding which require principal repayments starting in August
2009 and continuing until December 2011.  In the event we are unable
to repay or refinance these debt obligations it may adversely affect our ability
to fund our ongoing operations and, as repayment of such indebtedness has
priority over the payment of cash distributions to Unitholders, to distribute
cash to Unitholders.
  We are
required to comply with covenants under our credit facilities, the 2007 Senior
Notes, the 2008 Senior Notes and the 2008 Pounds Sterling Senior
Notes.  In the event that we do not comply with covenants under one or
more of these debt instruments, our access to capital could be restricted or
repayment could be required, which could adversely affect our ability to fund
our ongoing operations and, as repayment of such indebtedness has priority over
the payment of cash distributions to Unitholders, to distribute cash to
Unitholders.
  We
may be unable to successfully compete with other companies in our industry,
which could negatively affect the market price of our Trust Units and
distributions to our Unitholders.
  There is
strong competition relating to all aspects of the oil and gas
industry.  We compete with numerous other trusts and conventional
exploration and production companies for, among other things:
  ·
              capital;
 ·
              the
      acquisition of properties with longer life reserves and properties with
      exploitation and development opportunities;
and
 ·
              access
      to equipment, refining capacity, drilling and service rigs and processing
      facilities.
  The SIFT
Tax imposed by the Government of Canada is expected by us to make our Trust
Units less attractive as consideration for acquisitions.  As a result
of such increasing competition, we expect that it will become more difficult to
acquire producing assets and reserves on accretive terms.  We also
compete for skilled industry personnel with a substantial number of other oil
and gas companies and trusts.
  We
will require additional financing from time to time, which may result in
Unitholders suffering dilution.  If we are unable to obtain additional
financing at all or on reasonable terms, the amount of funds flow available for
distribution to Unitholders will be reduced.
  In the
normal course of making capital investments to maintain and expand our oil and
gas reserves, additional Trust Units may be issued which may result in a decline
in production per Trust Unit and reserves per Trust
Unit.  Additionally, from
   51
  time to
time, we may issue Trust Units from treasury in order to reduce debt and
maintain a more optimal capital structure.  Conversely, to the extent
that external sources of capital, including the issuance of additional Trust
Units, becomes limited or unavailable, our ability to make the necessary capital
investments to maintain or expand our oil and gas reserves will be
impaired.  We believe that the SIFT Tax imposed by the Government of
Canada will substantially eliminate the competitive advantage that we and other
energy trusts have enjoyed relative to our industry competitors in raising
capital in a tax-efficient manner.  To the extent that we are required
to use additional funds flow to finance capital expenditures or property
acquisitions or to pay debt service charges or to reduce debt, the amount of
funds flow available for distribution to Unitholders will be
reduced.
  Our
hedging program could result in us not realizing the full benefit of oil and
natural gas price increases.
  We may
manage the risk associated with changes in commodity prices by entering into oil
or natural gas price hedges.  If we hedge our commodity price
exposure, we could forego the benefits we would otherwise experience if
commodity prices increase.  In addition, commodity hedging activities
could expose us to cash and income losses.  To the extent that we
engage in risk management activities, there are credit risks associated with
counterparties with which we contract.
  Being
a limited purpose trust makes us largely dependent upon the operations and
assets of the Operating Entities.  If the oil and natural gas reserves
associated with the Operating Entities' resource properties are not supplemented
through additional development activities or the acquisition of oil and natural
gas properties, the ability of the Operating Entities to continue to generate
funds flow from operations for distribution to Unitholders may become adversely
affected.
  We are
entirely dependent upon the operations and assets of the Operating Entities
through our ownership, directly and indirectly, of securities of the Operating
Entities, including the common shares of PWPL, the Internal Notes and the
NPIs.  Accordingly, our ability to pay cash distributions to
Unitholders are dependent upon the ability of the Operating Entities to meet
their interest, principal, dividend and other distribution obligations on the
securities of the Operating Entities and the NPIs.  The Operating
Entities' income is received from the production of oil and natural gas from the
Operating Entities' resource properties and is susceptible to the risks and
uncertainties associated with the oil and natural gas industry
generally.
  If
we are unable to acquire additional reserves, the value of our Trust Units and
distributions to Unitholders will decline.
  Distributions
of income from our properties, absent commodity price increases or cost
effective exploration, acquisition and development activities, will decline over
time in a manner consistent with declining production from typical oil, natural
gas and natural gas liquids reserves.  As we distribute a portion of
our funds flow to Unitholders, we do not reinvest funds flow in the same manner
as some non-trust industry participants and we only conduct limited exploratory
activities.  Accordingly, absent equity capital injections or
increased debt levels, our production levels and reserves will decline over time
and, absent changes to other factors such as increases in commodity prices, the
level of income available for distributions will also decline over
time.
  Our
future oil and natural gas reserves and production, and therefore our funds
flow, will be highly dependent on our success in exploring and exploiting our
reserves and land base and acquiring additional reserves.  Without
reserve additions through acquisition, exploration or development activities,
our reserves and production will decline over time as our existing reserves are
depleted.
  To the
extent that external sources of capital, including the issuance of additional
Trust Units, become limited or unavailable, our ability to make the necessary
capital investments to maintain or expand our oil and natural gas reserves may
be impaired.  To the extent that we are required to use higher
proportions of funds flow to finance capital expenditures or property
acquisitions, the level of funds flow available for distributions will be
reduced.
  There can
be no assurance that we will be successful in developing or acquiring additional
reserves on terms that meet our investment objectives.
   52
  Fluctuations
in foreign currency exchange rates and interest rates could adversely affect our
business, and adversely affect the market price of our Trust Units and
distributions to our Unitholders.
  World oil
prices are based on United States dollars and the Canadian dollar price received
by Canadian producers is therefore affected by the Canadian/U.S. dollar exchange
rate, which fluctuates over time.  In recent years, the Canadian
dollar has increased materially in value against the United States dollar and
has at times traded above par against the United States dollar (although the
Canadian dollar has recently declined sharply against the United States
dollar).  Any such material increases in the value of the Canadian
dollar negatively affect our production revenues.  Any future
strengthening of the Canadian dollar against the United States dollar could
negatively affect the funds available for future distributions and the future
value of our reserves as determined by independent evaluators.
  An
increase in interest rates could result in a significant increase in the amount
we pay to service debt, resulting in a decrease in distributions to Unitholders,
which would negatively impact the market price of the Trust Units.
  Actual
reserves will vary from reserves estimates and those variations could be
material, and negatively affect the market price of our Trust Units and
distributions to our Unitholders.
  There are
numerous uncertainties inherent in estimating quantities of oil, natural gas and
natural gas liquid reserves and resources and funds flows to be derived
therefrom, including many factors beyond our control.  The reserve and
associated funds flow information set forth herein represents estimates
only.  In general, estimates of economically recoverable oil and
natural gas reserves and resources and the future net funds flows therefrom are
based upon a number of variable factors and assumptions, such as:
  ·
              historical
      production from the properties;
 ·
              production
      rates;
 ·
              ultimate
      reserve recovery;
 ·
              timing
      and amount of capital expenditures;
 ·
              marketability
      of oil and natural gas;
 ·
              royalty
      rates;
 ·
              the
      assumed effects of regulation by governmental agencies;
  and
 ·
              future
      operating costs;
  all of
which may vary from actual results.  As a result, estimates of the
economically recoverable oil and natural gas reserves or estimates of resources
attributable to any particular group of properties, classification of such
reserves based on risk of recovery and estimates of future net revenues expected
therefrom prepared by different engineers, or by the same engineers at different
times, may vary.  Our actual production, revenues and development and
operating expenditures will vary from reserve and resource estimates thereof and
such variations could be material.
  Estimates
of proved reserves that may be developed and produced in the future are
sometimes based upon volumetric calculations and upon analogy to similar types
of reserves rather than actual production history.  Estimates based on
these methods are generally less reliable than those based on actual production
history.  Subsequent evaluation of the same reserves based upon
production history and production practices will result in variations in the
estimated reserves and such variations could be material.
  In
accordance with applicable securities laws, GLJ and Sproule have used forecast
price and cost estimates in calculating reserve quantities included
herein.  Actual future net funds flows will be affected by other
factors including but not limited to actual production levels, supply and demand
for oil and natural gas, curtailments or increases in consumption by oil and
natural gas purchasers, changes in governmental regulation or taxation and the
impact of inflation on costs.
  Actual
production and funds flows derived from reserves will vary from the reserve
estimates contained in the engineering reports summarized herein, and such
variations could be material.  The engineering reports summarized
herein are based in part on the assumption that certain activities will be
undertaken by us in future years and the further assumption that such activities
will be successful.  The reserves and estimated funds flows to be
derived therefrom contained in the engineering reports summarized herein will be
reduced, in future years, to the extent that such activities are not undertaken
or, if undertaken, do not achieve the level of success assumed in the
engineering reports summarized herein.
   53
  Our
operation of oil and natural gas wells, and our participation in oil and natural
gas wells operated by others, could subject us to environmental claims and
liability and/or increased compliance costs, all of which could affect the
market price of our Trust Units and reduce distributions to
Unitholders.
  All
phases of the oil and natural gas business present environmental risks and
hazards and are subject to environmental regulation pursuant to a variety of
federal, provincial and local laws and regulations.  Environmental
legislation provides for, among other things, restrictions and prohibitions on
spills, releases or emissions of various substances produced in association with
oil and natural gas operations.  The legislation also requires that
wells, pipelines and associated facility sites be operated, maintained,
abandoned and reclaimed to the satisfaction of applicable regulatory
authorities.  Compliance with such legislation can require significant
expenditures and a breach may result in the imposition of fines and penalties,
some of which may be material.  Environmental legislation is evolving
in a manner expected to result in stricter standards and enforcement, larger
fines and legal liability, and potentially increased capital expenditures and
operating costs.  The discharge of oil, natural gas or other
pollutants into the air, soil or water may give rise to liabilities to
governments and third parties and may require our Operating Entities to incur
costs to remedy such discharge.  Furthermore, we believe the political
climate appears to favour new programs for environmental laws and regulation,
particularly in relation to the reduction of emissions.  Any such
programs, laws or regulations, if proposed and enacted, may contain emission
reduction targets that we cannot meet, and financial penalties or charges could
be incurred as a result of the failure to meet such targets.
  In
particular, there is uncertainty regarding the Kyoto Protocol, the federal
government's Clean Air Act of 2006, the federal government's Action Plan to
Reduce Greenhouse Gases and Air Pollution announced on April 26, 2007 (the
"Action Plan") and the
federal government's update to the Action Plan announced on March 10, 2008 (the
"Updated Action
Plan").  The Clean Air Act proposes to reduce greenhouse gas
emissions and other contaminants; however, emission targets and compliance
deadlines differ from those outlined in the Kyoto Protocol which was ratified by
Canada.  The Action Plan (also known as ecoACTION) includes the
regulatory framework for air emissions.  The Updated Action Plan
provides additional guidance with respect to the federal government plan to
reduce greenhouse gas emissions by 20% by 2020 and by 60% to 70% by
2050.  The Updated Action Plan is primarily directed towards
industrial emissions from certain specified industries including the oil sands,
oil and gas and refining industries.  If passed, the Clean Air Act,
the Action Plan and the Updated Action Plan may have adverse operational and
financial implications to us.  Provincial emission reduction
requirements, such as those contained in Alberta's Climate Change and Emissions
Management Act, in addition to the plan announced by the Alberta government on
January 24, 2008, may require the reduction of emissions or emissions intensity
of our operations and facilities.  The direct or indirect costs of
these regulations may adversely and materially affect our
business.  No assurance can be given that environmental laws will not
result in a curtailment of production or a material increase in the costs of
production, development or exploration activities or otherwise adversely affect
our financial condition, results of operations or prospects.  Future
changes in other environmental legislation could occur and result in stricter
standards of enforcement, larger fines and liability, and increased capital
expenditures and operating costs, which could have a material adverse effect on
our financial condition or results of operations.  See "Industry
Conditions – Environmental Regulation" herein.
  Given the
evolving nature of the debate related to climate change and the control of
greenhouse gases and resulting requirements, it is not currently possible to
predict either the nature of those requirements or the impact on us and our
operations and financial condition.
  We
depend upon our management and other key personnel and the loss of one or more
of such individuals could negatively affect our business.
  Unitholders
depend upon the management of PWPL in respect of the administration and
management of all matters relating to our operations.  The success of
our operations depends largely upon the skills and expertise of our senior
management and other key personnel.  Our continued success depends
upon our ability to retain and recruit such personnel.  Investors who
are not willing to rely on the management of PWPL should not invest in our
securities.
  Our
strategy in the current economic and industry environment may subject us to
certain risks.
 
 In light
of the current economic and commodity price environment, we have reduced our
planned 2009 capital expenditures and our monthly distribution to Unitholders
significantly from 2008 levels, in each case in an effort to minimize further
increases in debt levels and position ourselves to capitalize on acquisition
opportunities. There are certain risks associated with this strategy, including
that: (i) reduced capital spending will decrease future production and cash flow
available for distributions; (ii) reducing cash distributions to Unitholders may
reduce the trading price or value of the Trust Units in the
   54
  market;
and (iii) we may not be able to execute an attractive acquisition.  In
addition, if the current commodity price environment continues, we may be
required to further revise our strategy, and any further changes may adversely
affect the cash distributions to Unitholders or the value or trading price of
the Trust Units.
 
 Distributions
on our Trust Units are variable and may be reduced or suspended
entirely.
 
 The
actual cash flow available for distribution to Unitholders is dependent on the
amount of cash flow paid to the Trust by its Operating Entities and can vary
significantly from period to period for a number of reasons, including among
other things: (i) the Operating Entities' operational and financial performance
(including fluctuations in the quantity of their oil, NGLs and natural gas
production and the sales price that they realize for such production (after
hedging contract receipts and payments)); (ii) fluctuations in the costs to
produce oil, NGLs and natural gas, including royalty burdens, and to administer
and manage the Trust and its subsidiaries; (iii) the amount of cash required or
retained for debt service or repayment; (iv) amounts required to fund capital
expenditures and working capital requirements; and (v) foreign currency exchange
rates and interest rates. Certain of these amounts are, in part, subject to the
discretion of the Board of Directors, which regularly evaluates the Trust's
distribution payout with respect to anticipated cash flows, debt levels, capital
expenditures plans and amounts to be retained to fund acquisitions and
expenditures. In addition, our level of distribution per Trust Unit will be
affected by the number of outstanding Trust Units and other securities that may
be entitled to receive cash distributions, such as any exchangeable shares that
our Subsidiaries may issue from time to time. Distributions may be increased,
reduced or suspended entirely depending on our operations and the performance of
our assets. The market value of the Trust Units may deteriorate if the Trust is
unable to meet distribution expectations in the future, and that deterioration
may be material.
  The
Government of Canada has enacted tax law changes that will tax our distributions
and therefore reduce the percentage of our funds flow from operations that is
available for distribution to Unitholders beginning in 2011 (or in certain
circumstances, earlier than 2011).
  On
October 31, 2006, the Federal Minister of Finance proposed the SIFT Tax, which
would deny the deduction of distributions at the trust level and subject any
income of certain publicly traded mutual fund trusts to tax at rates comparable
to the combined federal and provincial corporate tax and to treat such
distributions as taxable dividends to the unitholders.  On December
21, 2006, the Federal Minister of Finance released draft legislation to
implement the SIFT Tax pursuant to which, commencing January 1, 2011 (provided
we only experience "normal growth" and no "undue expansion" before then) certain
distributions from us which would have otherwise been taxed as ordinary income
generally will be characterized as dividends to our Unitholders and will be
subject to tax at the corporate rates at the trust level.  On June 22,
2007, the legislation received Royal assent.  The implementation of
the SIFT Tax is expected to result in adverse tax consequences to us and certain
Unitholders (including most particularly Unitholders that are tax deferred or
non-residents of Canada) and may impact the level of cash distributions from
us.
  We
believe that the SIFT Tax has reduced, and may further reduce, the value of our
Trust Units, which would be expected to increase our cost of raising capital in
the public capital markets.  In addition, we believe that the SIFT
Tax: (a) has substantially eliminated any competitive advantage that we and
other Canadian energy trusts have enjoyed relative to our corporate peers in
raising capital in a tax-efficient manner; and (b) may place us and other
Canadian energy trusts at a competitive disadvantage relative to certain of our
industry competitors.  The SIFT Tax may also make the Trust Units less
attractive as consideration for acquisitions in the future.  As a
result, it may become more difficult for us to compete effectively for
acquisition opportunities.
  The Trust
is a taxable entity under the Tax Act and is taxable only on income that is not
distributed or distributable to the Unitholders.  As the Trust
distributes all of its taxable income to the Unitholders pursuant to the Trust
Indenture and currently satisfies the requirements of the Tax Act applicable to
the Trust, the Trust does not expect to pay income taxes until the earlier of
January 1, 2011 or if and when it ceases to be a trust.  The SIFT Tax
will not impose a tax on distributions from entities, such as the Trust, until
January 1, 2011 as long as that the Trust experiences only "normal growth" as
set out in the guidelines described below.  Commencing in January
2011, the Trust will be liable for tax on all distributions of income paid or
payable to Unitholders, which distributions the Trust will no longer be able to
deduct in computing its taxable income.  The Trust currently has
significant tax pools and expects to continue to increase its tax pool base
until 2011.  Accordingly, it is expected that the Trust will be able
to shelter income for a period of time after the application of the SIFT
Tax.
  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.
   55
  As a
result, the adverse tax consequences resulting from the SIFT Tax could be borne
sooner than January 1, 2011.  On December 15, 2006, the Department of
Finance issued guidelines with respect to what is meant by "normal growth" in
this context.  Specifically, the Department of Finance stated that
"normal growth" would include equity growth within certain "safe harbour"
limits, measured by reference to a SIFT's market capitalization as of the end of
trading on October 31, 2006 (which would include only the market value of the
SIFT's issued and outstanding publicly-traded trust units, and not any
convertible debt, options or other interests convertible into or exchangeable
for trust units).  Those safe harbour limits are 40% for the period
from November 1, 2006 to December 31, 2007, and 20% each for calendar year
2008, 2009 and 2010.  Moreover, these limits are cumulative, so that
any unused limit for a period carries over into the subsequent
period.  Additional details of the Department of Finance's guidelines
include the following: (i) new equity for these purposes includes units and debt
that is convertible into units (and may include other substitutes for equity if
attempts are made to develop those); and (ii) replacing debt that was
outstanding as of October 31, 2006 with new equity, whether by a conversion into
trust units of convertible debentures or otherwise, will not be considered
growth for these purposes and will therefore not affect the safe
harbour.
  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 25, 2009, 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% in 2011 and 15% in
2012) plus the provincial SIFT tax rate discussed below.
  Pursuant
to proposed regulations to the Tax Act, the provincial SIFT Tax rate will be
based on the general provincial corporate income tax rate in each province in
which the Trust has a permanent establishment.  For purposes of
calculating this component of the tax, the general corporate taxable income
allocation formula will be used.  Specifically, the Trust's taxable
distributions, if any, will be allocated to provinces by taking half of the
aggregate of:
  ·
              that
      proportion of the Trust's taxable distributions, if any, for the year that
      the Trust's wages and salaries in the province are of its total wages and
      salaries in Canada; and
  ·
              that
      proportion of the Trust's taxable distributions, if any, for the year that
      the Trust's gross revenues in the province are of its total gross revenues
      in Canada.
  It is
anticipated that the Trust would be considered to have a permanent establishment
in Alberta only, where the provincial tax rate in 2011 is expected to be 10%,
which will result in an effective tax rate of 26.5% in 2011.  Taxable
distributions, if any, that are not allocated to any province, would instead be
subject to a 10% rate constituting the provincial component.
   56
  On July
14, 2008, the Federal Minister of Finance announced proposed amendments to the
Tax Act, including technical amendments to clarify certain aspects of the SIFT
Tax and to provide rules to facilitate the conversion of existing SIFTs into
corporations on a tax-deferred basis (the "Conversion
Rules").  The Conversion Rules address many of the principal
substantive and administrative issues that arise when structuring a corporate
conversion of an income trust under the Tax Act.  The Conversion Rules
contemplate two alternatives for the conversion of a publicly-traded SIFT into a
taxable Canadian corporation and the winding-up of the SIFT's underlying
structure.  The first alternative involves the winding-up of the SIFT
into a taxable Canadian corporation whereas the second approach involves the
distribution by the publicly-traded SIFT of shares of an underlying taxable
Canadian corporation to its unitholders.  The Conversion
Rules will generally only apply to the winding-up of a SIFT or a
distribution of shares completed after July 14, 2008 and before 2013.
Bill C-10, which received Royal Assent on March 12, 2009, contained legislation
implementing the Conversion Rules.
  The
long term effect of the SIFT Tax on us cannot be determined at this time, but
may be materially adverse to us and some or all of our
Unitholders.  There can be no assurance that we will be able to
generate sufficient tax pools and/or reorganize our legal and tax structure in
order to mitigate, in whole or in part, the expected impact of the SIFT
Tax.
  For
additional information, see "General Development of the Business – History and
Development – Year Ended December 31, 2006 – Changes to Taxation of Income
Trusts".
  It
is probable that we will convert to a corporation or other form of entity prior
to January 1, 2013.  The conversion may adversely impact some or all
of our Unitholders.  In addition, we will be subject to additional
risk factors that are relevant to the form of entity in to which we
convert.
 
 As a
result of the above-described changes to the taxation of income trusts, the
Trust may convert from an income trust structure to a corporate or other form of
entity, prior to the Trust becoming subject to the SIFT Tax for the financial
year beginning January 1, 2011. We are currently hesitant to make structural
changes prior to the end of 2010 unless opportunities arise, as we believe this
exemption period has value for our Unitholders. Even if we do not convert to a
corporation or other form of entity prior to January 1, 2011, it is likely that
such a conversion would be completed prior to January 1, 2013 in order to effect
the conversion without undue tax consequences for Penn West or its
Unitholders.  As discussed in more detail above, Bill C-10, which
received Royal Assent on March 12, 2009, contained legislation implementing the
SIFT Conversion Rules which facilitate the conversion of existing SIFTs into
corporations on a tax-deferred basis.  Unless circumstances change
within the current capital markets or the regulatory, tax or political
environment, we currently believe that we will most likely convert into a
dividend paying corporation. However, we are keeping our options open at this
time and cannot provide any assurances in this regard. If we do complete a
conversion to a corporate or other form of structure, the nature of a
Unitholder's investment will change, and although at this time we believe that
such a conversion may be completed without creating a taxable event for most
Unitholders for Canadian and U.S. federal income tax purposes, no assurance can
be given that such a conversion will not give rise to income tax liability.
However, going forward, there can be no assurance that the taxation of future
payments received from us in a corporate or other form will not give rise to tax
consequences that are more adverse to securityholders than the current treatment
of distributions to our Unitholders, and may differ depending on the
Unitholder's tax jurisdiction and whether the Unitholder is holding its
investment in a taxable or tax-deferred account.
 
 After
2010, the most important variables that will determine the level of cash taxes
incurred by us in a given year will be the price of crude oil and natural gas,
capital spending and the amount of tax pools available to us. With the current
forward prices for commodity prices and our current plans with respect to
production, costs and capital spending, we do not expect a significant change to
our overall tax costs until at least 2014, even if we were to convert to a
corporation during 2010. Even after 2014, we expect that our capital spending
will help shelter taxes and would expect cash taxes to average approximately 10%
to 12% of cash flow, which is not dissimilar to other oil and gas production
companies. However, if crude oil and natural gas prices were to strengthen
beyond the levels anticipated by the current forward market, our tax pools would
be utilized more quickly and we may experience higher than expected cash taxes
or payment of such taxes in an earlier time period. Moreover, we emphasize that
it is difficult to give guidance on future taxability as we operate within an
industry where various factors constantly change our outlook, including factors
such as acquisitions, divestments, capital spending levels, distribution levels
and commodity price changes.
 
 The
new Alberta royalty regime may adversely impact us and our operations and
reserves.
 
 In
December 2008, the Government of Alberta passed into law a "New Royalty
Framework", effective January 1, 2009. The Government of Alberta has offered oil
and gas producers a one-time option to select, for a five year period,
transitional
   57
  royalty
rates as an alternative to the New Royalty Framework in respect of certain new
wells spud on or after November 19, 2008. Additionally, on March 3, 2009, the
Government of Alberta announced a short-term incentive program to encourage the
drilling of new wells over the next twelve months, which includes lower initial
royalty rates and certain royalty credits. See "Industry Conditions – Provincial
Royalties and Incentives - Alberta" and "General Development of the Business –
History and Development – Year Ended December 31, 2008 – Revisions to Alberta
Royalty Regime". In 2008, approximately 55% of our crude oil and natural gas
production was from Alberta Crown leases. Given that we have not yet completed a
fiscal period operating under the New Royalty Framework and the fact that the
New Royalty Framework is sensitive to commodity price and production levels, it
is not possible at this time to determine the full impact of the New Royalty
Framework (including the transitional royalty rates and short-term incentives)
on our financial condition and operations, and in particular the extent to which
the New Royalty Framework could reduce our cash flow, which could in turn reduce
the cash otherwise available for distribution by us to our Unitholders. Our
reserves and the estimated future net revenue associated therewith, as contained
in the reserve reports summarized in this Annual Information Form, reflect the
revised royalty rates contemplated by the New Royalty Framework. Any adverse
impact on us from the New Royalty Framework will be particularly felt in periods
of high to mid-level commodity prices.
  We
may not be able to achieve the anticipated benefits of acquisitions and the
integration of acquisitions may result in the loss of key employees and the
disruption of on-going business relationships.
  We make
acquisitions and dispositions of businesses and assets in the ordinary course of
business.  Achieving the benefits of acquisitions depends in part on
successfully consolidating functions and integrating operations and procedures
in a timely and efficient manner, as well as our ability to realize the
anticipated growth opportunities and synergies from combining the acquired
businesses and operations with ours.  The integration of acquired
businesses may require substantial management effort, time and resources and may
divert management's focus from other strategic opportunities and operational
matters, and may also result in the loss of key employees, the disruption of
on-going business, supplier, customer and employee relationships and reportable
deficiencies in internal controls over financial reporting or information
technology general controls.  We continually assess the value and
contribution of services provided and assets required to provide such
services.  In this regard, non-core assets are periodically disposed
of, so that we can focus our efforts and resources more
efficiently.  Depending on the state of the market for such non-core
assets, certain of our non-core assets, if disposed of, could be expected to
realize less than their carrying value in our financial statements.
  The
incorrect assessment of value at the time of acquisitions could adversely affect
the value of our Trust Units and distributions to our Unitholders.
  Acquisitions
of oil and gas properties or companies will be based in large part on
engineering and economic assessments made by independent
engineers.  These assessments include a series of assumptions
regarding such factors as recoverability and marketability of oil and gas,
future prices of oil and gas and operating costs, future capital expenditures
and royalties and other government levies which will be imposed over the
producing life of the reserves.  Many of these factors are subject to
change and are beyond our control.  All such assessments involve a
measure of geological and engineering uncertainty that could result in lower
production and reserves than anticipated.  If actual reserves or
production are less than we expect, our funds flow from operations and
distributions to Unitholders could be negatively affected.
  Our
inability to manage growth could adversely affect our business and our
Unitholders.
  We may be
subject to growth related risks, including capacity constraints and pressure on
our internal systems and controls.  Our ability to manage growth
effectively will require us to continue to implement and improve our operational
and financial systems and to expand, train and manage our employee
base.  Our inability to deal with this growth could have a material
adverse impact on our business, operations and prospects.
  Changes
in Canadian income tax legislation and other laws may adversely affect us and
our Unitholders.
  Income
tax laws, or other laws or government incentive programs relating to the oil and
gas industry, such as the treatment of mutual fund trusts and resource taxation,
may in the future be changed or interpreted in a manner that adversely affects
us and our Unitholders.  Furthermore, tax authorities having
jurisdiction over us or our Unitholders may disagree with how we calculate our
income for tax purposes or could change administrative practises to our
detriment or the detriment of our Unitholders.
   58
  Our
indebtedness may limit the amount of distributions that we are able to pay to
our Unitholders, and if we default on our debt, the net proceeds of any
foreclosure sale would be allocated to the repayment of our lenders and other
creditors and only the remainder, if any, would be available for distribution to
our Unitholders.
  Amounts
paid in respect of interest and principal on debt we have incurred will reduce
funds available for distributions.  Variations in interest rates and
any scheduled principal repayments could result in significant changes in the
amount required to be applied to debt service before payment of the
NPIs.  Certain covenants in the agreements with our lenders may also
limit distributions in certain circumstances.  Increases in interest
rates could also result in decreases to the market value of our Trust
Units.  Although we believe our credit facilities and other debt
instruments will be sufficient for our immediate requirements, there can be no
assurance that the amount will be adequate for our future financial obligations
or that additional funds will be able to be obtained.
  Our
current credit agreement and other debt instruments are unsecured and we must
comply with certain financial debt covenants.  The lenders and other
debt holders could, in the future, require security over a portion of or
substantially all of our assets.  Should this occur, in the event that
we become unable to pay our debt service charges or otherwise commit an event of
default such as bankruptcy, the lender and other debt holders may foreclose on
or require us to sell our oil and gas and other assets.
  Changes
in the regulation of the oil and gas industry may adversely affect our
business.
  Oil and
natural gas operations (including exploration, production, pricing, marketing
and transportation operations) are subject to extensive controls and regulations
imposed by various levels of government that may be changed or amended from time
to time.  We have no control over these changes and amendments and the
impact that they may have on us, and any such impact could be material and
adverse.  See "Industry Conditions" herein, including in respect of
the Government of Alberta's NRF and related shallow rights reversion
program.
  Our
operations require licenses from various governmental
authorities.  There can be no assurance that we will be able to obtain
all necessary licenses and permits that may be required to carry out exploration
and development at our projects.
  Acquiring,
developing and exploring for oil and natural gas involves many
risks.  Losses resulting from the occurrence of one or more of these
risks may adversely affect our business and thus the value of our Trust Units
and distributions to our Unitholders.
  Acquiring,
developing and exploring for oil and natural gas involves many risks, which even
a combination of experience, knowledge and careful evaluation may not be able to
overcome.  These risks include, but are not limited to:
  ·
              encountering
      unexpected formations or pressures;
 ·
              premature
      declines of reservoirs;
 ·
              blow-outs,
      equipment failures and other
accidents;
 ·
              sour
      gas releases;
 ·
              uncontrollable
      flows of oil, natural gas or well
fluids;
 ·
              adverse
      weather conditions; and
 ·
              pollution
      and other environmental risks, such as fires and
  spills.
  Although
we maintain insurance in accordance with customary industry practice based on
our projected cost benefit analysis of maintaining such insurance, we are not
fully insured against all of these risks.  Losses resulting from the
occurrence of these risks could have a material adverse impact on
us.  Like other oil and natural gas trusts and companies, we attempt
to conduct our business and financial affairs so as to protect against political
and economic risks applicable to operations in the jurisdictions where we
operate but there can be no assurance that we will be successful in so
protecting our assets.
   59
   We
do not operate all of our properties and facilities.  Therefore, our
results of operations may be adversely affected by the failure of third party
operators, and harm to their business could cause delays and additional expenses
in receiving our revenues, which could adversely affect the market price of our
Trust Units and distributions to our Unitholders.
  Continuing
production from a property, and to some extent the marketing of production
therefrom, largely depend upon the ability of the operator of the property or
related facilities.  Operating costs on most properties have increased
over recent years.  To the extent the operator fails to perform these
functions properly, operating income will be reduced.  Payments from
production generally flow through the operator and there is a risk of delay and
additional expense in receiving such revenues if the operator becomes
insolvent.
  An
unforeseen defect in the chain of title to our oil and natural gas producing
properties may arise to defeat our claim, which could have an adverse affect on
the market price of our Trust Units and could reduce distributions to our
Unitholders.
  Although
title reviews may be conducted prior to the purchase of oil and natural gas
producing properties or the commencement of drilling wells, such reviews do not
guarantee or certify that an unforeseen defect in the chain of title will not
arise to defeat our claim, which could result in a reduction of the revenue
received by us and consequently the funds flow available for distribution to
Unitholders.
  The
termination or expiration of licenses and leases through which we or our
industry partners hold our interests in petroleum and natural gas substances
could adversely affect the market price of our Trust Units and distributions to
our Unitholders.
  Our
properties are held in the form of licenses and leases and working interests in
licenses and leases.  If we or the holder of the license or lease fail
to meet the specific requirement of a license or lease, the license or lease may
terminate or expire.  There can be no assurance that all of the
obligations required to maintain each license or lease will be
met.  The termination or expiration of a license or lease or the
working interest relating to a license or lease may have a material adverse
effect on our results of operations and business.
  We
are exposed to potential liabilities that may not be covered, in part or in
whole, by insurance.
  Our
involvement in the exploration and development of oil and natural gas properties
could subject us to liability for pollution, blowouts, property damage, personal
injury or other hazards.  Prior to commencing operations, we obtain
insurance in accordance with industry standards to address certain of these
risks.  Such insurance has limitations on liability that may not be
sufficient to cover the full extent of such liabilities.  In addition,
such risks may not, in all circumstances, be insurable or, in certain
circumstances, we may elect not to obtain insurance to deal with specific risks
due to the high premiums associated with such insurance or other
reasons.  The payment of such uninsured liabilities would reduce the
funds available to us.  The occurrence of a significant event that we
are not fully insured against, or the insolvency of the insurer of such event,
could have a material adverse effect on our financial position, results of
operations or prospects and will reduce funds flow otherwise distributable by
us.
  Distributions
might be reduced during periods in which we make capital expenditures using our
funds flow from operations, which could negatively affect the market price of
our Trust Units.
  Future
oil and natural gas reserves and hence revenues are highly dependent on our
success in exploiting existing properties and acquiring additional
reserves.  We also intend to distribute approximately 60% to 70% of
our net funds flow to Unitholders rather than reinvesting it in reserve
additions and production growth or maintenance.  Accordingly, if
external sources of capital, including the issuance of additional Trust Units,
become limited or unavailable on commercially reasonable terms, our ability to
make the necessary capital investments to maintain or expand our oil and natural
gas reserves will be impaired.  To the extent that we are required to
use funds flow to finance capital expenditures or property acquisitions, the
level of funds flow available for distribution to Unitholders will be
reduced.  Additionally, we cannot guarantee that we will be successful
in exploring for and developing additional reserves or acquiring additional
reserves on terms that meet our investment objectives.  Without these
reserve additions, our reserves will decline and as a consequence,
   60
  either
production from, or the average reserve life of, our properties will
decline.  Either decline may result in a reduction in the value of our
Trust Units and in a reduction in cash available for distributions to
Unitholders.
  Delays
in business operations could adversely affect distributions to Unitholders and
the market price of the Trust Units.
  In
addition to the usual delays in payment by purchasers of oil and natural gas to
the operators of the properties, and by the operator to us, payments between any
of such parties may also be delayed by restrictions imposed by lenders, delays
in the sale or delivery of products, delays in the connection of wells to a
gathering system, blowouts or other accidents, recovery by the operator of
expenses incurred in the operation of properties or the establishment by the
operator of reserves for such expenses.
  We
may in the future expand our operations into new geographical regions where our
existing management does not have experience.  In addition, we may in
the future acquire new types of energy related assets in respect of which our
existing management does not have experience.  Any such expansion or
acquisition could result in our exposure to new risks that if not properly
managed could ultimately have an adverse effect on our business, the market
price of our Trust Units and distributions to our Unitholders.
  The
operations and expertise of our management are currently focused on oil and gas
production and exploration and development in the Western Canadian Sedimentary
Basin and, since the completion of the Canetic Acquisition, in North Dakota,
Montana and Wyoming in the United States.  In the future, we may
acquire oil and gas properties outside these geographic areas.  In
addition, the Trust Indenture does not limit our activities to oil and gas
production and development, and we could acquire other energy related assets,
such as additional oil and natural gas processing plants, upgraders or
pipelines.  Expansion of our activities into new areas may present new
additional risks or alternatively, significantly increase the exposure to one or
more of the present risk factors that may result in our future operational and
financial conditions being adversely affected.
  Non-Residents
of Canada may be subject to additional taxation by Canadian or foreign
governments that may adversely affect them.
  The Tax
Act and the tax treaties between Canada and other countries may impose
additional withholding or other taxes on the cash distributions or other
property paid by us to Unitholders who are Non-Residents of Canada, and these
taxes may change from time to time.  Since January 1, 2005, a 15%
Canadian withholding tax is applied to any return of capital portion of
distributions made to Non-Resident Unitholders.
  Additionally,
the reduced "Qualified Dividend" rate of 15% tax which has applied to our
distributions under current U.S. tax laws is scheduled to expire at the end of
2010 and there is no assurance that this reduced tax rate will be renewed by the
U.S. government at such time.
  Furthermore,
it is anticipated that the implementation of the SIFT Tax may have tax
consequences for Non-Residents of Canada that are more adverse than the tax
consequences to other classes of Unitholders.
  Your
rights as a Unitholder differ from the rights associated with other types of
investments.
  The Trust
Units do not represent a traditional investment in the oil and natural gas
sector and should not be viewed by investors as shares in PWPL.  The
Trust Units represent a fractional interest in our assets.  As holders
of Trust Units, Unitholders will not have the statutory rights normally
associated with ownership of shares of a corporation including, for example, the
right to bring "oppression" or "derivative" actions.  The rights of
Unitholders are specifically set forth in the Trust Indenture.  In
addition, trusts are not defined as recognized entities within the definitions
of legislation such as the Bankruptcy and Insolvency Act
(Canada), the Companies'
Creditors Arrangement Act (Canada) and in some cases the Winding Up and Restructuring
Act (Canada).  As a result, in the event of an insolvency or
restructuring, a Unitholder's position as such may be quite different than that
of a shareholder of a corporation.  Our sole assets are the NPIs and
other investments in securities of our Operating Entities, including the
Internal Notes.  The price per Trust Unit is a function of anticipated
income available for distributions, the oil and gas assets acquired by us and
our ability to effect long-term growth in the value of our
assets.  The market price of the Trust Units is sensitive to a variety
of market conditions including, but not
   61
  limited
to, interest rates and our ability to acquire suitable oil and natural gas
properties.  Changes in market conditions may adversely affect the
trading price of the Trust Units.
  The Trust
Units are not "deposits" within the meaning of the Canada Deposit Insurance Corporation
Act (Canada) and are not insured under the provisions of that Act or any
other legislation.  Furthermore, we are not a trust company and,
accordingly, we are not registered under any trust and loan company legislation
as we do not carry on or intend to carry on the business of a trust
company.
  The
limited liability of Unitholders is uncertain.
  The Trust
Indenture provides that no Unitholder will be subject to any liability in
connection with our obligations and affairs and, in the event that a court
determines Unitholders are subject to any such liabilities, the liabilities will
be enforceable only against, and will be satisfied only out of, our
assets.  Pursuant to the Trust Indenture, we will indemnify and hold
harmless each Unitholder from any costs, damages, liabilities, expenses, charges
and losses suffered by a Unitholder resulting from or arising out of such
Unitholder not having such limited liability.
  The Trust
Indenture provides that all written instruments signed by or on our behalf must
contain a provision to the effect that such obligation will not be binding upon
Unitholders personally.  Personal liability may also arise in respect
of claims against us that do not arise under contracts, including claims in
tort, claims for taxes and possibly certain other statutory
liabilities.  The possibility of any personal liability of this nature
arising is considered unlikely.  The Income Trusts Liability Act
(Alberta) came into force on July 1, 2004.  The legislation provides
that a unitholder will not be, as a beneficiary, liable for any act, default,
obligation or liability of the trustee that arises after the legislation came
into force.
  Our
operations will be conducted, upon the advice of counsel, in such a way and in
such jurisdictions as to avoid as far as possible any material risk of liability
on the Unitholders for claims against us.
  Nevertheless,
notwithstanding the terms of the Trust Indenture and the aforementioned
legislation, Unitholders may not be protected from our liabilities to the same
extent as shareholders are protected from the liabilities of corporations and we
cannot guarantee that any assets would be available to fully reimburse
Unitholders should they become subject to personal liability and seek to rely
upon the indemnification of Unitholders provided for in the Trust
Indenture.
  We
use enhanced oil recovery methods that are subject to significant risk factors
which could lead to the delay or cancellation of some or all of our enhanced oil
recovery projects, which could adversely affect the market price of our Trust
Units and our distributions to Unitholders.
  Penn West
utilizes new drilling and completion technologies, including horizontal multi
fracture completions, intended to increase the resource recovery from known
producing oil and natural gas fields.  There is potential Penn West
may not realize the anticipated increase in resource recovery from the
employment of such techniques due to particular reservoir characteristics or
other adverse factors.  We currently use conventional artificial lift
technology to recover heavy oil from bitumen deposits at our Peace River oil
sands project.  The potential or planned use of enhanced oil recovery
("EOR") methods such as
steam injection (Steam Assisted Gravity Drainage, Cyclical Steam Stimulation and
Steam Flooding), solvent injection and firefloods to increase the ultimate
recovery of oil resources in place are subject to significant risk
factors.  These factors, which could lead to a delayed or cancelled
EOR application in the Peace River oil sands project, include but are not
limited to the following:
  ·
              changing
      economic conditions (commodity pricing, operating and capital expenditure
      fluctuations);
 ·
              changing
      engineering and technical conditions (ability to apply EOR methods to the
      reservoir and the production response
thereto);
 ·
              the
      large development program may need to spread over a longer time period
      than initially planned due to requirement to allocate capital expenditures
      to different periods;
 ·
              surface
      access and deliverability issues (First Nations relations, weather,
      pipeline, road and processing
matters);
 ·
              environmental
      regulations, relating to such items as green house gas emissions and
      access to water,  which could impact capital and operating
      costs; and
 ·
              financing
      (the availability of sufficient financing on acceptable
      terms).
   62
  The use
or potential or planned use of carbon dioxide miscible flooding to increase the
oil recovery from large legacy oil pools such as Pembina and South Swan Hills is
subject to significant risk factors which could lead to the delay or
cancellation of some or all of these projects.  These factors include,
but are not limited to:
  ·
              carbon
      dioxide infrastructure (the capture and transportation of the miscible
      agent to us at an economic cost);
 ·
              changing
      economic conditions (commodity pricing, operating and capital expenditure
      fluctuations);
 ·
              changing
      engineering and technical conditions (ability to apply carbon dioxide EOR
      methods to the reservoir and the production response
    thereto);
 ·
              the
      large development program may need to be spread over a longer time period
      than planned due to capital allocation
  requirements;
 ·
              the
      need to obtain required approvals from regulatory authorities from time to
      time;
 ·
              surface
      access and deliverability issues (weather, pipeline, road and processing
      matters); and
 ·
              financing
      (the availability of sufficient financing on acceptable
      terms).
  The
engineering, geological, production and associated dewatering techniques
employed on coal bed methane projects are relatively new in the Western Canadian
Sedimentary Basin and their application to our coal bed methane prone properties
is subject to this risk in addition to risk factors similar to those listed in
the preceding paragraphs related to the Peace River oil sands and carbon dioxide
miscible flooding.
  Unitholders
may suffer dilution.
  We may
make future acquisitions or enter into financings or other transactions
involving the issuance of our securities, which may be dilutive to
Unitholders.  In addition, we may determine to redeem the currently
outstanding Convertible Debentures for Trust Units or to settle the interest
and/or pay the redemption price at maturity of such Convertible Debentures by
issuing additional Trust Units.  Unitholders may suffer dilution in
the event of any such issuance of Trust Units.
  Seasonal
factors and unexpected weather patterns may lead to declines in our activities
and thereby adversely affect our business, the market price of our Trust Units
and distributions to our Unitholders.
  The level
of activity in the Canadian oil and gas industry is influenced by seasonal
weather patterns.  Wet weather and spring thaw may make the ground
unstable.  Consequently, municipalities and provincial transportation
departments enforce road bans that restrict the movement of rigs and other heavy
equipment, thereby reducing activity levels.  Also, certain oil and
gas producing areas are located in areas that are inaccessible other than during
the winter months because the ground surrounding the sites in these areas
consists of swampy terrain.  Seasonal factors and unexpected weather
patterns may lead to declines in our exploration, development and production
activities and thereby adversely affect our results of operations and
business.
  Changes
to Canadian federal income tax legislation or other factors could result in us
losing our mutual fund trust status, which would have an adverse effect on the
market price of the Trust Units and distributions to our
Unitholders.
  In order
for us to maintain our status as a mutual fund trust under the Tax Act, we must
not be established or maintained primarily for the benefit of Non-Residents
unless we satisfy the requirements of certain exceptions.  The Trust
Indenture provides that we will use our best commercial efforts to maintain our
status as a mutual fund trust under the Tax Act.  Generally speaking,
the Tax Act provides that a trust will permanently lose its "mutual fund trust"
status (which is essential to the income trust structure) if it is established
or maintained primarily for the benefit of Non-Residents (which is generally
interpreted to mean that the majority of unitholders must not be Non-Residents),
unless at the relevant time, "all or substantially all" of the trust's property
consists of property other than taxable Canadian property (the "TCP
Exception").  Based on information obtained by us through our
transfer agent and financial intermediaries, in February 2009, we estimate that
approximately 61% of our issued and outstanding Trust Units were held by
Non-Residents.  We have determined that we currently meet the
requirement of the TCP Exception, and as a result, the Trust Indenture does not
currently have a specific limit on the percentage of Trust Units that may be
owned by Non-Residents.
  There is
no assurance that the TCP Exception will continue to be available to us or that
the Government of Canada will not introduce new changes or proposals to tax
regulations directed at Non-Resident ownership which, given our level
of
   63
  Non-Residents
ownership, may result in us losing our mutual fund trust status or could
otherwise detrimentally affect us and the market price of the Trust
Units.
  If
we cease to qualify as a "mutual fund trust" under the Canadian tax laws,
adverse tax consequences would arise for the Trust and our
Unitholders.
  For such
period of time as we operate in a trust structure, we intend to continue to
qualify as a mutual fund trust for purposes of Canadian federal income tax
laws.  We may not, however, always be able to satisfy any future
requirements for the maintenance of mutual fund trust status.  Should
our status as a mutual fund trust be lost or successfully challenged by a
relevant tax authority, certain adverse consequences may arise for us and our
Unitholders.  Some of the significant consequences of losing mutual
fund trust status are as follows:
  ·
              We
      would be taxed on certain types of income distributed to Unitholders,
      including income generated by the royalties we hold.  Payment of
      this tax may have adverse consequences for some Unitholders, particularly
      Unitholders that are not residents of Canada and residents of Canada that
      are otherwise exempt from Canadian income tax or hold their Trust Units in
      a tax deferred account.
 
 ·
              We
      would cease to be eligible for the capital gains refund mechanism
      available under Canadian tax laws if we ceased to be a mutual fund
      trust.
 
 ·
              Trust
      Units held by Unitholders that are not residents of Canada would become
      taxable Canadian property.  These Non-Resident holders would be
      subject to Canadian income tax on any gains realized on a disposition of
      Trust Units held by them.
 
 ·
              Trust
      Units would cease to be a qualified investment for trusts governed by
      registered retirement savings plans ("RRSPs"), registered
      education savings plans ("RESPs"), deferred profit
      sharing plans ("DPSPs"), registered
      disability savings plan ("RDSPs"), registered
      retirement income funds ("RRIFs") and tax free
      savings accounts ("TFSAs") (collectively,
      the "Exempt Plans").  Where,
      at the end of a month, a RRSP, DPSP, RESP or RRIF holds Trust Units that
      cease to be a qualified investment, the plan must, in respect of that
      month, pay a tax equal to 1% of the fair market value of the Trust Units
      at the time such Trust Units were acquired by the plan.  Trusts
      governed by RRSPs, RDSPs, TSFAs or RRIFs which hold Trust Units that are
      not qualified investments will be subject to tax on the income
      attributable to the Trust Units while they are not qualified investments,
      including the full capital gains, if any, realized on the disposition of
      such Trust Units.  Where a trust governed by a RRSP or a RRIF
      acquires Trust Units that are not qualified investments, the value of the
      investment is included in the income of the annuitant for the year of the
      acquisition.  Trusts governed by RESPs which hold Trust Units
      that are not qualified investments can have their registration revoked by
      the CRA.  The holder of a RDSP or TSFA which holds Trust Units
      that are not qualified investments will be subject to tax equal to 50% of
      the fair market value of the Trust
Units.
  In
addition, we may take certain measures in the future to the extent we believe
necessary to ensure that we maintain our status as a mutual fund
trust.  These measures could be adverse to certain Unitholders,
particularly Non-Residents.
  There
might not always be an active trading market in the United States and/or Canada
for the Trust Units and/or the Convertible Debentures.
  While
there is currently an active trading market for the Trust Units in both the
United States and Canada, we cannot guarantee that an active trading market will
be sustained in either country.  If an active trading market in the
Trust Units is not sustained, the trading liquidity of the Trust Units will be
limited and the market value of the Trust Units may be reduced.
  There is
not currently an active trading market for the Convertible Debentures in Canada,
and we cannot guarantee that an active trading market will
develop.  If an active trading market in the Convertible Debentures
does not develop, the trading liquidity of the Convertible Debentures will
remain limited and the market value of the Convertible Debentures may be
adversely affected.
   64
  The
economic impact on us of claims of aboriginal title is unknown.
  Aboriginal
peoples have claimed aboriginal title and rights to portions of western
Canada.  We are not aware that any claims have been made in respect of
our properties and assets; however, if a claim arose and was successful this
could have an adverse effect on our results of operations and
business.
  Our
exploration and development activities may be delayed if drilling and related
equipment is unavailable or if access to drilling locations is
restricted.  These events could have an adverse impact on our
business.
  Oil and
natural gas exploration and development activities depend on the availability of
drilling and related equipment (typically leased from third parties) in the
particular areas where such activities will be conducted.  Demand for
such limited equipment or access restrictions may affect the availability of
such equipment to us and may delay exploration and development
activities.  To the extent we are not the operator of our oil and gas
properties, we depend on such operators for the timing of activities related to
such properties and are largely unable to direct or control the activities of
the operators.
  Our
directors and management may have conflicts of interest that may create
incentives for them to act contrary to or in competition with the interests of
our Unitholders.
  The
directors and officers of PWPL are engaged in, and will continue to engage in,
other activities in the oil and natural gas industry and, as a result of these
and other activities, the directors and officers of PWPL may become subject to
conflicts of interest.  The ABCA provides that in the event that a
director has an interest in a contract or proposed contract or agreement, the
director must disclose his interest in such contract or agreement and must
refrain from voting on any matter in respect of such contract or agreement
unless otherwise provided under the ABCA.  To the extent that
conflicts of interest arise, such conflicts will be resolved in accordance with
the provisions of the ABCA and our Code of Business Conduct and
Ethics.
  Our
Trust Units may from time to time trade at a price that is less than our net
asset value per Trust Unit.
  Our net
asset value from time to time will vary depending upon a number of factors
beyond our control, including oil and gas prices.  The trading price
of the Trust Units from time to time is determined by a number of factors, some
of which are beyond our control and such trading price may be greater or less
than our net asset value.
  The
ability of residents of the United States to enforce civil remedies against us
and our directors, officers and experts may be limited.
  Both the
Trust and PWPL are organized under the laws of Alberta, Canada and our
respective principal places of business are in Canada.  Most of our
directors and all of our officers and the experts named herein are residents of
Canada, and a substantial portion of our assets and all or a substantial portion
of the assets of such persons are located outside the United
States.  As a result, it may be difficult for investors in the United
States to effect service of process within the United States upon those
directors, officers and experts who are not residents of the United States or to
enforce against them judgments of United States courts based upon civil
liability under the United States federal securities laws or the securities laws
of any state within the United States.  There is doubt as to the
enforceability in Canada against us or against any of our directors, officers or
experts who are not residents of the United States, in original actions or in
actions for enforcement of judgments of United States courts of liabilities
based solely upon the United States federal securities laws or the securities
laws of any state within the United States.
  Canadian
and United States practices differ in reporting reserves and production and our
estimates may not be comparable to those of companies in the United
States.
  We report
our production and reserve quantities in accordance with Canadian practices and
specifically in accordance with NI 51-101.  These practices are
different from the practices used to report production and to estimate reserves
in reports and other materials filed with the SEC by companies in the United
States.
  The SEC
generally permits oil and gas companies, in their filings with the SEC, to
disclose only proved reserves after the deduction of royalties and interests of
others which are those reserves that a company has demonstrated by actual
production or conclusive formation tests to be economically producible under
existing economic and operating conditions.  The
   65
  securities
regulatory authorities in Canada have adopted NI 51-101, which imposes oil and
gas disclosure standards for Canadian public issuers engaged in oil and gas
activities.  NI 51-101 permits oil and gas issuers, in their filings
with Canadian securities regulators, to disclose not only proved reserves but
also probable reserves, and to disclose reserves and production on a gross basis
before deducting royalties.  Probable reserves are of a higher risk
and are less likely to be accurately estimated or recovered than proved
reserves.  Because we are permitted to disclose reserves in accordance
with Canadian disclosure requirements, we have disclosed herein reserves
designated as "probable reserves".  If required to be prepared in
accordance with U.S. disclosure requirements, the SEC's guidelines would
prohibit reserves in this category from being included.  Moreover, as
permitted by NI 51-101, we have determined and disclosed the net present value
of future net revenue from our reserves using only forecast prices and
costs.  The SEC does not permit the disclosure of the net present
value of future net revenue from reserves based on forecast prices and costs and
generally requires that prices and costs be held constant at levels in effect at
the date of the reserve report.
  Our
distributions are declared in Canadian dollars and Non-Resident investors are
therefore subject to foreign exchange risk that could adversely affect the
amount of distributions received by them.
  Our
distributions are declared in Canadian dollars and converted to foreign
denominated currencies at the spot exchange rate at the time of
payment.  As a consequence, investors are subject to foreign exchange
risk.  To the extent that the Canadian dollar weakens with respect to
their currency, the amount of the distribution will be reduced when converted to
their home currency.
  If
oil and gas prices decline, we may be required under Canadian GAAP and/or U.S.
GAAP to write down the value of our assets.
  Canadian
GAAP requires that management apply certain accounting policies and make certain
estimates and assumptions that affect reported amounts in our consolidated
financial statements.  Under Canadian GAAP, the amounts at which
petroleum and natural gas property and equipment are carried as net assets on
the balance sheet are subject to a cost-recovery or "ceiling" test, which is
based in part upon estimated future net funds flows from reserves.  If
net capitalized costs exceed the estimated recoverable amounts, we will have to
charge the amount of the excess to net income.  A decline in the net
value of oil and natural gas properties could cause capitalized costs to exceed
the cost ceiling, resulting in a non-cash charge against net
income.  The value of oil and gas properties is highly dependent upon
the prices of oil and natural gas.
  Under
U.S. GAAP, the estimated recoverable amounts are calculated based on estimated
future net funds flows from proved reserves discounted at 10% and using
commodity prices in effect on the balance sheet date.  The use of
discounting and constant prices results in a greater likelihood of a write-down
under U.S. GAAP than Canadian GAAP.
  In
certain circumstances we may be required under Canadian GAAP to write down the
value of the goodwill recorded on our balance sheet and incur a non-cash charge
against net income.
  Canadian
GAAP requires that goodwill balances be assessed at least annually for
impairment and that any permanent impairment be charged to net
income.  A permanent reduction in reserves, decline in commodity
prices, and/or reduction in the Trust Unit price may indicate goodwill
impairment.  As at December 31, 2008 we had $2.020 billion recorded on
our balance sheet as goodwill arising primarily out of the Petrofund Acquisition
and the Canetic Acquisition.  An impairment would result in a
write-down of the goodwill value and a non-cash charge against net
income.  The calculation of impairment value is subject to management
estimates and assumptions.
  A
decrease in the fair market value of our hedging instruments could result in a
non-cash charge against our income under Canadian GAAP.
  Canadian
GAAP in respect of accounting for financial instruments may result in non-cash
charges against income as a result of changes in the fair market value of
hedging instruments.  A decrease in the fair market value of the
hedging instruments as the result of fluctuations in commodity prices and/or
foreign exchange rates may result in a non-cash charge against
income.
   66
  United
States Unitholders may be subject to passive foreign investment company
rules.
 
 United
States Unitholders (meaning, for the purposes of this section, tax residents for
United States federal income tax purposes as defined under Section 7701 of the
United States Internal Revenue Code, as amended (the "Code")) should be aware that
the United States Internal Revenue Service may determine that the Trust is a
"passive foreign investment company" (a "PFIC") under Section 1297(a)
of the Code for the 2008 taxable year and in subsequent taxable years. The Trust
will be a PFIC if at least 75% of its income consists of dividends, interest,
and other passive items or if 50% or more of the average value of its assets (on
a gross value basis) consist of assets that would produce passive
income.  In determining whether it is a PFIC, a foreign corporation is
required to take into account a pro rata portion of the income and assets of
each corporation in which it owns, directly or indirectly, at least a 25%
interest.  To date, we have received advice that the Trust should not
be considered a PFIC for the years 2002 through 2007, and we do not expect to be
considered a PFIC for 2008 or 2009.
 
 If the
Trust is or becomes a PFIC, adverse United States federal income tax
consequences may apply. Any gain recognized on the sale of Trust Units and any
excess distributions (as defined under Section 1291(b) of the Code) paid on the
Trust Units must be ratably allocated to each day in a United States
Unitholder's holding period for the Trust Units. The amount of any such gain or
excess distribution allocated to prior years of such United States Unitholder's
holding period for the Trust Units generally will be subject to United States
federal income tax at the highest tax rate applicable to ordinary income in each
such prior year, and the United States Unitholder will be required to pay
interest on the resulting tax liability for each such prior year, calculated as
if such tax liability had been due in each such prior year.
 
 Alternatively,
a United States Unitholder that makes a "qualified electing fund" election
generally will be subject to United States federal income tax on such United
States Unitholder's pro 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.
  We
are uncertain what impact the conversion to International Financial Reporting
Standards will have on us.
  The
Accounting Standards Board of the Canadian Institute of Chartered Accountants
has announced that Canadian publicly accountable enterprises are required to
adopt International Financial Reporting Standards ("IFRS"), as issued by the
International Accounting Standards Board, effective January 1,
2011.  IFRS will require increased financial statement disclosure as
compared to Canadian GAAP. Although IFRS uses a conceptual framework similar to
Canadian GAAP, differences in accounting policies will need to be addressed by
us. We are currently considering the impact a conversion to IFRS will have on
us, including on our financial statements.
  We
cannot assure you that the distributions you receive over the life of your
investment will meet or exceed your initial capital investment, which is at
risk.
  Trust
Units will have no value when the underlying petroleum and natural gas
properties can no longer be economically produced and, as a result, cash
distributions may not represent a "yield" in the traditional sense and are not
comparable to bonds or other fixed yield securities, where investors are
entitled to a full return of the principal amount of debt on maturity in
addition to a return on investment through interest
payments.  Distributions can represent areturn of or a return on Unitholders'
capital.
   67
  Your
redemption right as a Unitholder is limited.
  Unitholders
have a limited right to require us to repurchase their Trust Units, which is
referred to as a redemption right.  See "Information Relating to Penn
West – Trust Indenture – Right of Redemption" herein for details of the
redemption right.  It is anticipated that the redemption right will
not be the primary mechanism for Unitholders to liquidate their
investment.  The right to receive cash in connection with a redemption
is subject to limitations.  Any securities which may be distributed in
specie to Unitholders in connection with a redemption may not be listed on any
stock exchange and a market may not develop for such securities.  In
addition, there may be resale restrictions imposed by law upon the recipients of
the securities pursuant to the redemption right.
  MATERIAL CONTRACTS
  Except
for contracts entered into in the ordinary course of business, the only
contracts that are material to us and that were entered into within the most
recently completed financial year or subsequent thereto, or before the most
recently completed financial year but which are still material and are still in
effect, are the following:
  (a)
              the
      Trust Indenture described under "Information Relating to Penn West – Trust
      Indenture";
  (b)
              the
      Administration Agreement referred to under "Information Relating to Penn
      West – Trust Indenture – Our Management" and "Corporate
      Governance";
  (c)
              the
      Debenture Indentures described under "Information Relating to Penn West –
      Convertible Debentures";
  (d)
              the
      credit agreement dated January 10, 2008 among PWPL and certain
      lenders and other parties in respect of Penn West's $4 billion syndicated
      credit facility, which agreement is described in Note 6 to Penn
      West's audited comparative consolidated financial statements for the year
      ended December 31, 2008, which note is incorporated by reference
      herein;
  (e)
              the
      note purchase agreement dated May 31, 2007 among PWPL and the holders
      of PWPL's US$475 million principal amount of 2007 Senior Notes, which
      agreement is described in Note 6 to Penn West's audited comparative
      consolidated financial statements for the year ended December 31,
      2008, which note is incorporated by reference herein.  See also
      "General Development of the Business – History and Development - Year
      Ended December 31, 2007 – Private Placement of 2007 Senior
      Notes";
  (f)
              the
      note purchase agreement dated May 29, 2008 among PWPL and the holders of
      PWPL's US$480 million and Cdn$30 million principal amount of 2008 Senior
      Notes, which agreement is described in Note 6 to Penn West's audited
      comparative consolidated financial statements for the year ended
      December 31, 2008, which note is incorporated by reference
      herein.  See also "General Development of the Business – History
      and Development - Year Ended December 31, 2008 – Private Placement of 2008
      Senior Notes"; and
  (g)
              the
      note purchase agreement dated July 31, 2008 among PWPL and the holders of
      PWPL's £57 million principal amount of 2008 Pounds Sterling Senior Notes,
      which agreement is described in Note 6 to Penn West's audited
      comparative consolidated financial statements for the year ended
      December 31, 2008, which note is incorporated by reference
      herein.  See also "General Development of the Business – History
      and Development - Year Ended December 31, 2008 – Private Placement of 2008
      Pounds Sterling Senior Notes".
  Copies of
each of these documents have been filed on SEDAR at www.sedar.com.
  LEGAL PROCEEDINGS AND REGULATORY
ACTIONS
  There are
no legal proceedings that Penn West is or was a party to, or that any of Penn
West's property is or was the subject of, during the most recently completed
financial year, that were or are material to Penn West, and there are no such
material legal proceedings that Penn West knows to be
contemplated.  For the purposes of the foregoing, a legal proceeding
is not considered to be "material" by us if it involves a claim for damages and
the amount involved, exclusive of interest and costs, does not exceed ten
percent of our current assets, provided that if any proceeding presents in large
degree the same legal and
   68
  factual
issues as other proceedings pending or known to be contemplated, we have
included the amount involved in the other proceedings in computing the
percentage.
  There
were no: (i) penalties or sanctions imposed against Penn West by a court
relating to securities legislation or by a security regulatory authority during
the most recently completed financial year; (ii) any other penalties or
sanctions imposed by a court or regulatory body against Penn West that would
likely be considered important to a reasonable investor in making an investment
decision; or (iii) settlement agreements Penn West entered into before a
court relating to securities legislation or with a securities regulatory
authority during Penn West's most recently completed financial
year.
  TRANSFER AGENTS AND
REGISTRARS
  The
transfer agent and registrar for the Trust Units in Canada is CIBC Mellon Trust
Company at its principal offices in Calgary, Alberta and Toronto,
Ontario.  The transfer agent and registrar for the Trust Units in the
United States is Mellon Investor Services LLC at its principal offices in New
York, New York.
  The
transfer agent and registrar for the 7.2% Debentures and the 8% 2005 Debentures
is Valiant Trust Company at its principal offices in Calgary, Alberta and
Toronto, Ontario.  The transfer agent and registrar for the 6.5% 2005
Debentures is Olympia Trust Company at its principal offices in Calgary, Alberta
and Toronto, Ontario.  The transfer agent and registrar for the 6.5%
2006 Debentures and the 8% 2004 Debentures is Computershare Trust Company of
Canada at its principal offices in Calgary, Alberta and Toronto,
Ontario.
  INTEREST OF MANAGEMENT AND OTHERS IN
MATERIAL TRANSACTIONS
  There
were no material interests, direct or indirect, of any director or executive
officer of PWPL, any person or company that beneficially owns, or controls or
directs, directly or indirectly, more than 10% of the outstanding Trust Units,
or any known associate or affiliate of any such person, in any transaction
within the three most recently completed financial years or during the current
financial year that has materially affected or is reasonably expected to
materially affect Penn West.
  INTERESTS OF EXPERTS
  There is
no person or company whose profession or business gives authority to a report,
valuation, statement or opinion made by such person or company and who is named
as having prepared or certified a report, valuation, statement or opinion
described or included in a filing, or referred to in a filing, made under
National Instrument 51-102 by us during, or related to, our most recently
completed financial year, other than GLJ and Sproule, our independent
engineering evaluators (GLJ and Sproule each an "Engineer" and collectively,
the "Engineers"), KPMG
LLP ("KPMG"), our
auditors, and Deloitte & Touche LLP, Canetic's former auditors.
  The
registered or beneficial interests, direct or indirect, in any securities or
other property of Penn West or of one of its associates or
affiliates:  (i) held by an Engineer and by the "designated
professionals" (as defined in National Instrument 51-102) of the Engineer, when
that Engineer prepared the report, valuation, statement or opinion referred to
above; (ii) received by an Engineer and by the "designated professionals"
of that Engineer, after the time specified above; or (iii) to be received
by an Engineer and by the "designated professionals" of that Engineer; in each
case, represented less than 1% of each class of our outstanding
securities.
  KPMG is
the auditor of Penn West and is independent within the meaning of the Rules of
Professional Conduct of the Institute of Chartered Accountants,
Alberta.
  Neither
GLJ, Sproule or KPMG, nor any director, officer or employee of any of such
companies, is or is expected to be elected, appointed or employed as a director,
officer or employee of Penn West or of any of our associate or affiliate
entities.  John A. Brussa, the Chairman of PWPL, is a partner of
Burnet, Duckworth & Palmer LLP, a law firm which renders legal services to
us.
   69
  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 (collectively "Penn West") is responsible for
the preparation and disclosure of information with respect to Penn West's oil
and gas activities in accordance with securities regulatory
requirements.  This information includes reserves data which are
estimates of proved reserves and probable reserves and related future net
revenue as at December 31, 2008, estimated using forecast prices and
costs.
  Independent
qualified reserves evaluators (or in some cases qualified reserves auditors)
have evaluated (or in some cases audited) Penn West's reserves
data.  The report of the independent qualified reserves evaluators (or
in some cases qualified reserves auditors) is presented below.
  The
Reserves Committee of the Board of Directors of PWPL has:
   (a)
                reviewed
      Penn West's procedures for providing information to the independent
      qualified reserves evaluators (or in some cases qualified reserves
      auditors);
 (b)
              met
      with the independent qualified reserves evaluators (or in some cases
      qualified reserves auditors) to determine whether any restrictions
      affected the ability of the independent qualified reserves evaluators (or
      in some cases qualified reserves auditors) to report without reservation;
      and
  (c)
              reviewed
      the reserves data with management and the independent qualified reserves
      evaluators (or in some cases qualified reserves
  auditors).
  The
Reserves Committee of the Board of Directors of PWPL has reviewed Penn West's
procedures for assembling and reporting other information associated with oil
and gas activities and has reviewed that information with
management.  The Board of Directors has, on the recommendation of the
Reserves Committee, approved:
  (a)
                  the
      content and filing with securities regulatory authorities of
      Form 51-101F1 containing reserves data and other oil and gas
      information;
 (b)
                the
      filing of Form 51-101F2 which is the report of the independent
      qualified reserves evaluators (or in some cases qualified reserves
      auditors) on the reserves data;
and
  (c)
                the
      content and filing of this
report.
 Because
the reserves data are based on judgments regarding future events, actual results
will vary and the variations may be material.  However, any variations
should be consistent with the fact that reserves are categorized according to
the probability of their recovery.
  (signed)
      William E. Andrew
              (signed)
      Murray R. 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 CommitteeSeptember
      15, 2009
  
  APPENDIX
A-2
  REPORT
ON RESERVES DATA
  (Form
51-101 F2)
  To the
Board of Directors of Penn West Petroleum Ltd. ("PWPL") on behalf of Penn West
Energy Trust (collectively "Penn West"):
  1.
              We
      have evaluated (or in some cases audited) Penn West's reserves data as at
      December 31, 2008.  The reserves data are estimates of
      proved reserves and probable reserves and related future net revenue as at
      December 31, 2008, estimated using forecast prices and
      costs.
  2.
              The
      reserves data are the responsibility of PWPL's management.  Our
      responsibility is to express an opinion on the reserves data based on our
      evaluation (or in some cases our
audit).
  3.
              We
      carried out our evaluation (or in some case or audit) in accordance with
      standards set out in the Canadian Oil and Gas Evaluation Handbook (the
      "COGE Handbook")
      prepared jointly by the Society of Petroleum Evaluation Engineers (Calgary
      Chapter) and the Canadian Institute of Mining, Metallurgy &
      Petroleum (Petroleum Society).
  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, 2008, and
      identifies the respective portions thereof that we have evaluated and
      audited and reported on to PWPL's Board of
  Directors:
  Net
      Present Value of Future Net Revenue
                  (millions
      before income taxes, 10% discount rate)Independent
      Qualified
                Reserves
      Evaluator or
                Auditor
              Description
      and
                Preparation
      Date of Evaluation / Audit Report
              Location
      of
                Reserves
              Audited
              
              
              Evaluated
              
              Reviewed
              
              TotalGLJ
      Petroleum
                Consultants
      Ltd.
              February
      24, 2009
              Canada
              
              -
              
              
              $7,868
              
              
              -
              
              $7,868Sproule
      Associates Limited
              February
      26, 2009
              Canada
              $1,064
              
              
              $3,582
              
              
              -
              
              $4,646Sproule
      Associates Limited
              February
      26, 2009
              USA
              
              -
              
              
              
              $88
              
              
              -
              
              
              $88
  6.
              In
      our opinion, the reserves data respectively evaluated or audited by us
      have, in all material respects, been determined and are in accordance with
      the COGE Handbook.  We express no opinion on the reserves data
      that we reviewed but did not audit or
evaluate.
  7.
              We
      have no responsibility to update our reports referred to in
      paragraph 4 for events and circumstances occurring after their
      respective preparation dates.
  8.
              Because
      the reserves data are based on judgements regarding future events, actual
      results will vary and the variations may be material.  However,
      any variations should be consistent with the fact that reserves are
      categorized according to the probability of their
  recovery.
  Executed
as to our report referred to above:
  (signed)
      GLJ Petroleum Consultants Ltd.
                Calgary,
      Alberta, Canada
                September
      15, 2009
              
              (signed)
      Sproule Associates Limited
                Calgary,
      Alberta, Canada
                September
      15, 2009
  
  APPENDIX
A-3
  STATEMENT
OF RESERVES DATA AND OTHER OIL AND GAS INFORMATION
  Our
statement of reserves data and other oil and gas information is set forth below
(the "Statement").  The
effective date of the Statement is December 31, 2008 and the preparation
date of the Statement is March 26, 2009.  The Report of
Management and Directors on Reserves Data and Other Information on Form 51-101F3
and the Report on Reserves Data by GLJ and Sproule on Form 51-101F2 are
attached as Appendices A-1 and A-2, respectively, to this Annual Information
Form.
  Disclosure
of Reserves Data
  The
reserves data set forth below is based upon: (i) an evaluation prepared by GLJ
with an effective date of December 31, 2008 contained in the GLJ Report
dated February 24, 2009; and (ii) an evaluation and audit prepared by Sproule
with an effective date of December 31, 2008 contained in the Sproule Report
dated February 26, 2009.  The reserves data summarizes our oil,
natural gas liquids and natural gas reserves and the net present values of
future net revenue from these reserves using forecast prices and costs, not
including the impact of any hedging activities.  The reserves data
conforms with the requirements of NI 51-101.  We engaged GLJ to
evaluate approximately 60% of our proved and proved plus probable
reserves.  We engaged Sproule to evaluate approximately 32% and to
audit approximately 8% of our proved and proved plus probable
reserves.  See also "Notes to Reserve Data Tables" below.
  The
Engineering Reports include Alberta crown royalties in accordance with the
Alberta New Royalty Framework (NRF) which passed provincial legislation in
December 2008.  The Engineering Reports do not take into account
either the transitional royalty rate program announced by the Government of
Alberta on November 19, 2008 or the new royalty incentive program announced by
the Government of Alberta on March 3, 2009.  See "Industry Conditions
– Provincial Royalties and Incentives – Alberta" for details of these
programs.
  The
majority of our proved plus probable reserves are located in Canada in the
provinces of Alberta, British Columbia, Saskatchewan and Manitoba, and in the
Northwest Territories.  We also have minor proved plus probable
reserves interests in the United States in the States of Montana, Wyoming and
North Dakota.  The reserves information presented below does not
report reserves that are located in the United States separately.  Our
properties located in the United States have proved plus probable gross reserves
of approximately 6 MMboe, which represents less than onepercent of our total
proved plus probable reserves, and have a before tax net present value
discounted at 10 percent of approximately $88 million, which represents less
than one percent of the total value of our proved plus probable
reserves.
  It
should not be assumed that the estimates of future net revenues presented in the
tables below represent the fair market value of the reserves.  There
is no assurance that the forecast prices and costs assumptions will be attained
and variances could be material.  The recovery and reserves estimates
of crude oil, natural gas liquids and natural gas reserves provided herein are
estimates only and there is no guarantee that the estimated reserves will be
recovered.  Actual crude oil, natural gas and natural gas liquid
reserves may be greater than or less than the estimates provided
herein.  For more information as to the risks involved, see "Risk
Factors".
   
  Reserves
Data (Forecast Prices and Costs)
  SUMMARY
OF OIL AND GAS RESERVES
 as of
December 31, 2008
 FORECAST
PRICES AND COSTS
   RESERVESLIGHT
      AND MEDIUM OIL
              
              
              HEAVY
      OILRESERVES
      CATEGORY
              
              Gross
                  (MMbbl)
              
              
              Net
                  (MMbbl)
              
              
              Gross
                  (MMbbl)
              
              
              Net
                  (MMbbl)PROVEDDeveloped
    Producing
              
              
              221
              
              
              
              190
              
              
              
              53
              
              
              
              49Developed
      Non-Producing
              
              
              5
              
              
              
              4
              
              
              
              3
              
              
              
              3Undeveloped
              
              
              37
              
              
              
              31
              
              
              
              6
              
              
              
              5TOTAL
      PROVED
              
              
              263
              
              
              
              225
              
              
              
              62
              
              
              
              57PROBABLE
              
              
              89
              
              
              
              74
              
              
              
              31
              
              
              
              27TOTAL
      PROVED PLUS PROBABLE
              
              
              352
              
              
              
              298
              
              
              
              94
              
              
              
              84
 
   RESERVESNATURAL
      GAS
              
              
              NATURAL
      GAS LIQUIDSRESERVES
      CATEGORY
              
              Gross
                  (Bcf)
              
              
              Net
                  (Bcf)
              
              
              Gross
                  (MMbbl)
              
              
              Net
                  (MMbbl)PROVEDDeveloped
    Producing
              
              
              947
              
              
              
              811
              
              
              
              25
              
              
              
              18Developed
      Non-Producing
              
              
              65
              
              
              
              52
              
              
              
              1
              
              
              
              1Undeveloped
              
              
              62
              
              
              
              54
              
              
              
              1
              
              
              
              1TOTAL
      PROVED
              
              
              1,074
              
              
              
              916
              
              
              
              27
              
              
              
              19PROBABLE
              
              
              402
              
              
              
              337
              
              
              
              9
              
              
              
              7TOTAL
      PROVED PLUS PROBABLE
              
              
              1,476
              
              
              
              1,253
              
              
              
              37
              
              
              
              26
 
  RESERVESTOTAL
      OIL EQUIVALENTRESERVES
      CATEGORY
              
              Gross
                  (MMboe)
              
              
              Net
                  (MMboe)PROVEDDeveloped
    Producing
              
              
              457
              
              
              
              392Developed
      Non-Producing
              
              
              20
              
              
              
              16Undeveloped
              
              
              54
              
              
              
              46TOTAL
      PROVED
              
              
              532
              
              
              
              454PROBABLE
              
              
              197
              
              
              
              164TOTAL
      PROVED PLUS PROBABLE
              
              
              729
              
              
              
              617
 
  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
                
                
                16,949
                
                
                
                11,497
                
                
                
                8,827
                
                
                
                7,231
                
                
                
                6,161
                
                
                
                22.52
                
                
                
                3.75Developed
      Non-Producing
                
                
                679
                
                
                
                462
                
                
                
                354
                
                
                
                288
                
                
                
                242
                
                
                
                22.12
                
                
                
                3.69Undeveloped
                
                
                2,117
                
                
                
                1,107
                
                
                
                643
                
                
                
                390
                
                
                
                238
                
                
                
                14.08
                
                
                
                2.35TOTAL
      PROVED
                
                
                19,746
                
                
                
                13,066
                
                
                
                9,824
                
                
                
                7,909
                
                
                
                6,641
                
                
                
                21.65
                
                
                
                3.61PROBABLE
                
                
                9,058
                
                
                
                4,521
                
                
                
                2,777
                
                
                
                1,914
                
                
                
                1,414
                
                
                
                16.96
                
                
                
                2.83TOTAL
      PROVED PLUS PROBABLE
                
                
                28,803
                
                
                
                17,587
                
                
                
                12,602
                
                
                
                9,823
                
                
                
                8,056
                
                
                
                20.44
                
                
                
                3.41
  Note:
  (1)
              The
      unit values are based on net reserve
volumes.
   NET
PRESENT VALUES OF FUTURE NET REVENUE
 AFTER
INCOME TAXES DISCOUNTED AT (%/year)
 FORECAST
PRICES AND COSTS
  RESERVES
      CATEGORY
              
              0%
                  (MM$)
              
              
              5%
                  (MM$)
              
              
              10%
                  (MM$)
              
              
              15%
                  (MM$)
              
              
              20%
                  (MM$)PROVEDDeveloped
Producing
              
              
              14,986
              
              
              
              10,528
              
              
              
              8,264
              
              
              
              6,873
              
              
              
              5,920Developed
      Non-Producing
              
              
              530
              
              
              
              372
              
              
              
              293
              
              
              
              244
              
              
              
              209Undeveloped
              
              
              1,594
              
              
              
              836
              
              
              
              480
              
              
              
              284
              
              
              
              164TOTAL
      PROVED
              
              
              17,111
              
              
              
              11,735
              
              
              
              9,038
              
              
              
              7,401
              
              
              
              6,293PROBABLE
              
              
              6,634
              
              
              
              3,352
              
              
              
              2,085
              
              
              
              1,455
              
              
              
              1,089TOTAL
      PROVED PLUS PROBABLE
              
              
              23,744
              
              
              
              15,087
              
              
              
              11,123
              
              
              
              8,856
              
              
              
              7,383
  
 3
  TOTAL
FUTURE NET REVENUE
 (UNDISCOUNTED)
 as of
December 31, 2008
 FORECAST
PRICES AND COSTS
  RESERVES
                    CATEGORY
                
                REVENUE
                    (MM$)
                
                
                ROYALTIES
                    (MM$)
                
                
                OPERATING
                    COSTS
                    (MM$)
                
                
                DEVELOPMENT
      COSTS
                    (MM$)
                
                
                ABANDONMENT
      AND
                    RECLAMATION
      COSTS
                    (MM$)
                
                
                FUTURE
                    NET
                    REVENUE
                    BEFORE
                    INCOME
      TAXES
                    (MM$)
                
                
                INCOME
                    TAXES
      (MM$)
                
                
                FUTURE
      NET REVENUE
                    AFTER
                    INCOME
                    TAXES
                    (MM$)Proved
      Reserves
                
                
                42,485
                
                
                
                6,507
                
                
                
                13,977
                
                
                
                1,120
                
                
                
                1,135
                
                
                
                19,746
                
                
                
                2,635
                
                
                
                17,111Proved
      Plus Probable Reserves
                
                
                60,421
                
                
                
                9,695
                
                
                
                18,873
                
                
                
                1,760
                
                
                
                1,291
                
                
                
                28,803
                
                
                
                5,059
                
                
                
                23,744
   FUTURE
NET REVENUE
 BY
PRODUCTION GROUP
 as of
December 31, 2008
 FORECAST
PRICES AND COSTS
  FUTURE
      NET REVENUE
                BEFORE
                INCOME
                TAXES
      (discounted at
              
              
              UNIT
      VALUE(3)RESERVES
      CATEGORY
              
              PRODUCTION
      GROUP
              
              10%/year)
                  (MM$)
              
              
              ($/bbl)
              
              
              ($/Mcf)Proved
      Reserves
              
              Light
      and Medium Crude Oil(1)
              
              
              4,263
              
              
              
              22.54
              
              
              
              3.76Heavy
      Oil(1)
              
              
              1,096
              
              
              
              17.95
              
              
              
              2.99Natural
      Gas(2)
              
              
              4,369
              
              
              
              22.17
              
              
              
              3.70Non-Conventional
      Oil and Gas Activities
              
              
              97
              
              
              
              14.86
              
              
              
              2.48TOTAL
              
              
              9,824
              
              
              
              21.65
              
              
              
              3.61Proved
      Plus Probable Reserves
              
              Light
      and Medium Crude Oil(1)
              
              
              5,196
              
              
              
              21.30
              
              
              
              3.55Heavy
      Oil(1)
              
              
              1,573
              
              
              
              17.63
              
              
              
              2.94Natural
      Gas(2)
              
              
              5,672
              
              
              
              20.86
              
              
              
              3.48Non-Conventional
      Oil and Gas Activities
              
              
              161
              
              
              
              13.85
              
              
              
              2.31TOTAL
              
              
              12,602
              
              
              
              20.44
              
              
              
              3.41
  Notes:
  (1)
              Including
      solution gas and other by-products.
 (2)
              Including
      by-products but excluding solution
gas.
 (3)
              Other
      company revenue and costs not related to a specific production group have
      been allocated proportionately to each production group.  Unit
      values are based on net reserve
volumes.
  Notes
to Reserves Data Tables
  1.
              Columns
      may not add due to rounding.
  2.
              The
      crude oil, natural gas liquids and natural gas reserves estimates
      presented in the Engineering Reports are based on the definitions and
      guidelines contained in the Canadian Oil and Gas Evaluation Handbook (the
      "COGE
      Handbook").  A summary of those definitions are set forth
      below:
   4
  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.
  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
   5
  to the
highest level sum of individual entity estimates for which reserves estimates
are presented).  Reported reserves should target the following levels
of certainty under a specific set of economic conditions:
  (a)
              at
      least a 90 percent probability that the quantities actually recovered will
      equal or exceed the estimated proved reserves;
  and
  (b)
              at
      least a 50 percent probability that the quantities actually recovered will
      equal or exceed the sum of the estimated proved plus probable
      reserves.
  A
qualitative measure of the certainty levels pertaining to estimates prepared for
the various reserves categories is desirable to provide a clearer understanding
of the associated risks and uncertainties.  However, the majority of
reserves estimates are prepared using deterministic methods that do not provide
a mathematically derived quantitative measure of probability.  In
principle, there should be no difference between estimates prepared using
probabilistic or deterministic methods.
  Additional
clarification of certainty levels associated with reserves estimates and the
effect of aggregation is provided in the COGE Handbook.
  3.
              Forecast
      prices and costs
  NI 51-101
defines "forecast prices and costs" as future prices and costs that are: (i)
generally acceptable as being a reasonable outlook of the future; and (ii) if,
and only to the extent that, there are fixed or presently determinable future
prices or costs to which we are legally bound by a contractual or other
obligation to supply a physical product, including those for an extension period
of a contract that is likely to be extended, those prices or costs rather than
the prices and costs referred to in subparagraph (i).
  The
forecast cost and price assumptions include increases in wellhead selling prices
and take into account inflation with respect to future operating and capital
costs.  Crude oil, natural gas and natural gas liquids benchmark
reference pricing, as at December 31, 2008, inflation and exchange rates
utilized in the Engineering Reports were as set forth below.  The
price assumptions set forth below were provided by GLJ and Sproule.
   6
  SUMMARY
OF PRICING AND INFLATION RATE ASSUMPTIONS
 as of
December 31, 2008
 FORECAST
PRICES AND COSTS
  OIL
              
              
              
              
              
              EDMONTON
      LIQUIDS PRICESYear
              
              WTI
                  Cushing
                  Oklahoma
                  ($US/bbl)
              
              
              Edmonton
                  Par
      Price
                  40oAPI
                  ($Cdn/bbl)
              
              
              Hardisty
                  Heavy
                  12oAPI
                  ($Cdn/bbl)
              
              
              Cromer
                  Medium
                  29.3oAPI
                  ($Cdn/bbl)
              
              
              NATURAL
                  GAS
                  AECO
                  ($Cdn/Mcf)
              
              
              Propane
                  ($Cdn/bbl)
              
              
              Butane
                  ($Cdn/bbl)
              
              
              Pentanes
                  Plus
                  ($Cdn/bbl)
              
              
              INFLATION
                  RATES(1)
                  %/year
              
              
              EXCHANGE
                  RATE(2)
                  ($US
      equals $1 Cdn)Forecast2009
              
              55.62
              
              
              
              66.98
              
              
              
              45.07
              
              
              
              58.58
              
              
              
              7.20
              
              
              
              41.96
              
              
              
              51.64
              
              
              
              68.46
              
              
              
              -
              
              
              
              0.812010
              
              65.71
              
              
              
              75.86
              
              
              
              52.17
              
              
              
              67.45
              
              
              
              7.75
              
              
              
              46.45
              
              
              
              57.91
              
              
              
              77.53
              
              
              
              2.0
              
              
              
              0.852011
              
              71.76
              
              
              
              81.75
              
              
              
              57.16
              
              
              
              73.14
              
              
              
              8.09
              
              
              
              50.02
              
              
              
              62.38
              
              
              
              83.55
              
              
              
              2.0
              
              
              
              0.862012
              
              82.30
              
              
              
              88.75
              
              
              
              63.38
              
              
              
              79.83
              
              
              
              8.54
              
              
              
              54.31
              
              
              
              67.72
              
              
              
              90.70
              
              
              
              2.0
              
              
              
              0.912013
              
              92.01
              
              
              
              95.44
              
              
              
              68.31
              
              
              
              85.89
              
              
              
              9.08
              
              
              
              58.37
              
              
              
              72.80
              
              
              
              97.54
              
              
              
              2.0
              
              
              
              0.952014
              
              93.85
              
              
              
              97.37
              
              
              
              69.70
              
              
              
              87.62
              
              
              
              9.28
              
              
              
              59.55
              
              
              
              74.27
              
              
              
              99.52
              
              
              
              2.0
              
              
              
              0.952015
              
              95.73
              
              
              
              99.33
              
              
              
              71.12
              
              
              
              89.39
              
              
              
              9.48
              
              
              
              60.76
              
              
              
              75.77
              
              
              
              101.52
              
              
              
              2.0
              
              
              
              0.952016
              
              97.64
              
              
              
              101.34
              
              
              
              72.56
              
              
              
              91.19
              
              
              
              9.69
              
              
              
              61.98
              
              
              
              77.30
              
              
              
              103.57
              
              
              
              2.0
              
              
              
              0.952017
              
              99.59
              
              
              
              103.39
              
              
              
              74.04
              
              
              
              93.04
              
              
              
              9.90
              
              
              
              63.23
              
              
              
              78.86
              
              
              
              105.67
              
              
              
              2.0
              
              
              
              0.952018
              
              101.59
              
              
              
              105.47
              
              
              
              75.54
              
              
              
              94.92
              
              
              
              10.11
              
              
              
              64.51
              
              
              
              80.45
              
              
              
              107.80
              
              
              
              2.0
              
              
              
              0.95Thereafter
              
              +2
              %
              
              
              +2
              %
              
              
              +2
              %
              
              
              +2
              %
              
              
              +2
              %
              
              
              +2
              %
              
              
              +2
              %
              
              
              +2
              %
              
              
              2.0
              
              
              
              0.95
  Notes:
  (1)
              Inflation
      rates for forecasting prices and
costs.
  (2)
              Exchange
      rates used to generate the benchmark reference prices in this
      table.
  Weighted
average actual prices realized, including hedging activities, for the year ended
December 31, 2008 were $8.04/Mcf for natural gas, $81.02/bbl for light and
medium crude oil, $74.55/bbl for heavy oil and $68.41/bbl for natural gas
liquids.
  4.
              Future
      Development Costs
  The
following table sets forth development costs deducted in the estimation of our
future net revenue attributable to the reserve categories noted
below.
    Forecast
      Prices and CostsYear
              
              Proved
      Reserves
                  (MM$)
              
              
              Proved
      Plus Probable Reserves (MM$)2009
              
              
              321
              
              
              
              4632010
              
              
              266
              
              
              
              3972011
              
              
              151
              
              
              
              2342012
              
              
              109
              
              
              
              1822013
              
              
              82
              
              
              
              132Total:
      Undiscounted for all years
              
              
              1,120
              
              
              
              1,760
  7
  We
currently expect to fund the development costs of the reserves through
internally generated funds flow.
  There can
be no guarantee that funds will be available or that we will allocate funding to
develop all of the reserves attributed in the Engineering
Reports.  Failure to develop those reserves would have a negative
impact on future production and funds flow and could result in negative
revisions to our reserves.
  The
interest and other costs of any external funding are not included in the
reserves and future net revenue estimates and would reduce reserves and future
net revenue to some degree depending upon the funding sources
utilized.  We do not currently anticipate that interest or other
funding costs would make development of any property uneconomic.
  5.
              Estimated
      future well abandonment costs related to reserve wells have been taken
      into account by GLJ and Sproule in determining the aggregate future net
      revenue therefrom.
  6.
              The
      forecast price and cost assumptions assumed the continuance of current
      laws and regulations.
  7.
              All
      factual data supplied to GLJ and Sproule was accepted as
      represented.  No field inspection was
  conducted.
  8.
              The
      estimates of future net revenue presented in the tables above do not
      represent fair market value.
  Reconciliations
of Changes in Reserves
  The
following table sets forth the reconciliation of our gross reserves as at
December 31, 2008, using forecast price and cost estimates derived from the
Engineering Reports.
  RECONCILIATION
OF
 COMPANY
GROSS RESERVES
 BY
PRODUCT TYPE
 FORECAST
PRICES AND COSTS
  LIGHT
      AND MEDIUM OIL(2)
              
              
              HEAVY
      OIL(2)
              
              
              NATURAL
      GAS(2)FACTORS
              
              Gross
                  Proved
                  (MMbbl)
              
              
              Gross
                  Probable
                  (MMbbl)
              
              
              Gross
                  Proved
                  Plus
                  Probable
                  (MMbbl)
              
              
              Gross
                  Proved
                  (MMbbl)
              
              
              Gross
                  Probable
                  (MMbbl)
              
              
              Gross
                  Proved
                  Plus
                  Probable
                  (MMbbl)
              
              
              Gross
                  Proved
                  (Bcf)
              
              
              Gross
                  Probable
                  (Bcf)
              
              
              Gross
                  Proved
                  Plus
                  Probable
                  (Bcf)December
      31, 2007
              190
              
              
              
              57
              
              
              
              248
              
              
              
              45
              
              
              
              16
              
              
              
              62
              
              
              
              703
              
              
              
              198
              
              
              
              901Extensions
              
              
              6
              
              
              
              3
              
              
              
              9
              
              
              
              1
              
              
              
              2
              
              
              
              4
              
              
              
              22
              
              
              
              9
              
              
              
              31Improved Recovery(1)
              4
              
              
              
              1
              
              
              
              5
              
              
              
              6
              
              
              
              13
              
              
              
              18
              
              
              
              16
              
              
              
              7
              
              
              
              23Technical
    Revisions
              2
              
              
              
              (2
              )
              
              
              (1
              )
              
              
              3
              
              
              
              (6
              )
              
              
              (2
              )
              
              
              13
              
              
              
              (1
              )
              
              
              12Discoveries
              
              
              -
              
              
              
              -
              
              
              
              -
              
              
              
              -
              
              
              
              -
              
              
              
              -
              
              
              
              3
              
              
              
              1
              
              
              
              4Acquisitions
              
              
              85
              
              
              
              30
              
              
              
              114
              
              
              
              13
              
              
              
              4
              
              
              
              17
              
              
              
              495
              
              
              
              186
              
              
              
              681Dispositions
              
              
              -
              
              
              
              -
              
              
              
              (1
              )
              
              
              -
              
              
              
              -
              
              
              
              -
              
              
              
              (15
              )
              
              
              (5
              )
              
              
              (19
              )Economic Factors
              2
              
              
              
              1
              
              
              
              3
              
              
              
              4
              
              
              
              2
              
              
              
              6
              
              
              
              17
              
              
              
              7
              
              
              
              24Production
              
              
              (26
              )
              
              
              -
              
              
              
              (26
              )
              
              
              (10
              )
              
              
              -
              
              
              
              (10
              )
              
              
              (179
              )
              
              
              -
              
              
              
              (179
              )December
      31, 2008
              263
              
              
              
              89
              
              
              
              352
              
              
              
              62
              
              
              
              31
              
              
              
              94
              
              
              
              1,074
              
              
              
              402
              
              
              
              1,476
  Note:
  (1)
              Improved
      recovery includes the following infill
drilling:
  Infill
      Drilling
              
              
              2
              
              
              
              -
              
              
              
              2
              
              
              
              5
              
              
              
              6
              
              
              
              11
              
              
              
              11
              
              
              
              5
              
              
              
              16
  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, 2007
              
              
              17
              
              
              
              5
              
              
              
              22
              
              
              
              370
              
              
              
              112
              
              
              
              482Extensions
              
              
              -
              
              
              
              -
              
              
              
              -
              
              
              
              11
              
              
              
              7
              
              
              
              18Improved Recovery(1)
              
              
              -
              
              
              
              -
              
              
              
              -
              
              
              
              13
              
              
              
              15
              
              
              
              28Technical
    Revisions
              
              
              -
              
              
              
              -
              
              
              
              -
              
              
              
              7
              
              
              
              (9
              )
              
              
              (1
              )Discoveries
              
              
              -
              
              
              
              -
              
              
              
              -
              
              
              
              -
              
              
              
              -
              
              
              
              1Acquisitions
              
              
              13
              
              
              
              5
              
              
              
              18
              
              
              
              193
              
              
              
              69
              
              
              
              262Dispositions
              
              
              -
              
              
              
              -
              
              
              
              -
              
              
              
              (3
              )
              
              
              (1
              )
              
              
              (4
              )Economic Factors
              
              
              -
              
              
              
              -
              
              
              
              -
              
              
              
              9
              
              
              
              4
              
              
              
              13Production
              
              
              (4
              )
              
              
              -
              
              
              
              (4
              )
              
              
              (69
              )
              
              
              -
              
              
              
              (69
              )December
      31, 2008
              
              
              27
              
              
              
              9
              
              
              
              37
              
              
              
              532
              
              
              
              197
              
              
              
              729
  Notes:
  (1)
              Improved
      recovery includes the following infill
drilling:
 
 Infill
      Drilling
              
              
              -
              
              
              
              -
              
              
              
              -
              
              
              
              9
              
              
              
              7
              
              
              
              16
 
 (2)
              Columns
      may not add due to rounding.
   Additional
Information Relating to Reserves Data
  Undeveloped
Reserves
   Undeveloped
reserves are attributed by GLJ and Sproule in accordance with standards and
procedures contained in the COGE Handbook.  Proved undeveloped
reserves are those reserves that can be estimated with a high degree of
certainty and are expected to be recovered from known accumulations where a
significant expenditure is required to render them capable of
production.  Probable undeveloped reserves are those reserves that are
less certain to be recovered than proved reserves and are expected to be
recovered from known accumulations where a significant expenditure is required
to render them capable of production.
  In some
cases, it will take longer than two years to develop these
reserves.  Penn West plans to develop approximately one-half of the
proved undeveloped reserves in the Engineering Reports over the next two years
and the significant majority of the proved undeveloped reserves over the next
five years.  There are a number of factors that could result in
delayed or cancelled development, including the following: (i) changing economic
conditions (due to pricing, operating and capital expenditure fluctuations);
(ii) changing technical conditions (including production anomalies, such as
water breakthrough or accelerated depletion); (iii) multi-zone developments (for
instance, a prospective formation completion may be delayed until the initial
completion is no longer economic); (iv) a larger development program may need to
be spread out over several years to optimize capital allocation and facility
utilization; and (v) surface access issues (including those relating to land
owners, weather conditions and regulatory approvals).
  Proved Undeveloped
Reserves
  The
following table discloses, for each product type, the gross volumes of proved
undeveloped reserves that were first attributed, net of conversions and
revisions, in each of the most recent three financial years and, in the
aggregate, before that time.
  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
              
              
              21
              
              
              
              21
              
              
              
              5
              
              
              
              5
              
              
              
              44
              
              
              
              44
              
              
              
              1
              
              
              
              12006
              
              
              13
              
              
              
              33
              
              
              
              -
              
              
              
              2
              
              
              
              8
              
              
              
              43
              
              
              
              -
              
              
              
              12007
              
              
              5
              
              
              
              34
              
              
              
              1
              
              
              
              1
              
              
              
              12
              
              
              
              38
              
              
              
              -
              
              
              
              12008
              
              
              9
              
              
              
              37
              
              
              
              5
              
              
              
              6
              
              
              
              44
              
              
              
              62
              
              
              
              -
              
              
              
              1
  GLJ and
Sproule have assigned 54 MMboe of proven undeveloped reserves in the Engineering
Reports under forecast prices and costs, together with $737 million of
associated undiscounted future capital expenditures.  Proven
undeveloped capital spending in the first two forecast years of the Engineering
Reports accounts for $445 million, or 60 percent, of the total
forecast.  These figures increase to $674 million, or 91 percent,
during the first five years of the Engineering Reports.  The majority
of our proven undeveloped reserves evaluated in the Engineering Reports are
attributable to future oil development from CO2injection,
infill drilling and water injection oil recovery ("EOR") projects.
  For
further information, see "Risk Factors".
  Probable
Undeveloped Reserves
  The
following table discloses, for each product type, the gross volumes of probable
undeveloped reserves that were first attributed, net of conversions and
revisions, in each of the most recent three financial years and, in the
aggregate, before that time.
  Year
              
              Light
      and Medium Oil
                  (MMbbl)
              
              
              Heavy
      Oil
                  (MMbbl)
              
              
              Natural
      Gas
                  (Bcf)
              
              
              NGLs
                  (MMbbl)First
                  Attributed
              
              
              Cumulative
      at
                  Year
      End
              
              
              First
                  Attributed
              
              
              Cumulative
      at
                  Year
      End
              
              
              First
                  Attributed
              
              
              Cumulative
      at
                  Year
      End
              
              
              First
                  Attributed
              
              
              Cumulative
      at
                  Year
      EndPrior
      thereto
              
              
              12
              
              
              
              12
              
              
              
              3
              
              
              
              3
              
              
              
              26
              
              
              
              26
              
              
              
              1
              
              
              
              12006
              
              
              11
              
              
              
              22
              
              
              
              -
              
              
              
              1
              
              
              
              7
              
              
              
              33
              
              
              
              1
              
              
              
              22007
              
              
              5
              
              
              
              24
              
              
              
              1
              
              
              
              1
              
              
              
              11
              
              
              
              26
              
              
              
              -
              
              
              
              22008
              
              
              11
              
              
              
              32
              
              
              
              14
              
              
              
              13
              
              
              
              57
              
              
              
              79
              
              
              
              1
              
              
              
              2
  GLJ and
Sproule have assigned 61 MMboe of probable undeveloped reserves in the
Engineering Reports under forecast prices and costs, together with $547 million
of associated undiscounted future capital expenditures.  Probable
undeveloped capital spending in the first two forecast years of the Engineering
Reports accounts for $232 million, or 43 percent, of the total
forecast.  These figures increase to $397 million or 72 percent,
during the first five years of the Engineering Reports.  The probable
undeveloped reserves evaluated in the Engineering Reports are primarily
associated with proved undeveloped reserve assignments but have a less likely
probability of being recovered than such associated proved undeveloped reserve
assignments.
  Significant
Factors or Uncertainties
  The
development schedule of our undeveloped reserves is based on forecast price
assumptions for the determination of economic projects.  The actual
prices that occur may be significantly lower or higher resulting in some
projects being delayed or accelerated, as the case may be.  See "Risk
Factors".
  We do not
anticipate that any significant economic factors or other significant
uncertainties will affect any particular components of our reserves
data.  However, our reserves can be affected significantly by
fluctuations in product pricing, capital expenditures, operating costs, royalty
regimes and well performance that are beyond our control.
  10
  Additional
Information Concerning Abandonment and Reclamation Costs
  Abandonment
and reclamation costs in respect of surface leases, wells, facilities and
pipelines (collectively, "A&R Costs") are primarily
comprised of well bore abandonment and reclamation costs, and liability issues
such as flare pit remediation and facility decommissioning, remediation, and
reclamation costs.  A&R Costs are estimated using our experience
conducting annual abandonment and reclamation programs over the past several
years.
  We review
suspended or standing well bores for reactivation, recompletion or sale and
conduct systematic abandonment programs for those well bores that do not meet
our criteria.  A portion of our liability issues are retired every
year and facilities are decommissioned when all the wells producing to them have
been abandoned.  All of our liability reduction programs take into
account seasonal access, high priority and stakeholder issues, and opportunities
for multi-location programs to reduce costs.
  As of
December 31, 2008, we expect to incur A&R Costs in respect of approximately
22,288 net well bores and 2,267 facilities.  The total amount of
A&R Costs, net of estimated salvage values, that we expect to incur,
including wells that extend beyond the 50-year limit in the Engineering Reports,
are summarized in the following table:
  Period
              
              Abandonment
      and Reclamation
                  Costs
      Escalated at 2%
                  Undiscounted
      (MM$)
              
              
              Abandonment
      and Reclamation
                  Costs
      Escalated at 2%
                  Discounted
      at 10% (MM$)Total
      liability as at December 31, 2008
              
              
              2,679
              
              
              
              272Anticipated
      to be paid in 2009
              
              
              45
              
              
              
              41Anticipated
      to be paid in 2010
              
              
              47
              
              
              
              39Anticipated
      to be paid in 2011
              
              
              49
              
              
              
              37
  The above
table includes certain A&R Costs, net of salvage values, not included in the
Engineering Reports and not deducted in estimating future net revenue as
disclosed earlier in this Annual Information Form.  Escalated at two
percent and undiscounted, the A&R Costs not deducted were $388 million, and
escalated at two percent and discounted at 10 percent, these A&R Costs
were $141 million.
  OTHER
OIL AND GAS INFORMATION
  Description
of Our Properties, Operations and Activities in Our Major Operating
Regions
  Introduction
  Penn West
participates in the exploration for, and the development and production of, oil
and natural gas principally in western Canada.  Our portfolio of
properties as at December 31, 2008 includes both unitized and non-unitized
oil and natural gas production.  In general, the properties contain
long-life, low-decline rate reserves and include interests in several major oil
and gas fields.  The majority of our proved plus probable reserves are
located in Canada in the provinces of Alberta, British Columbia, Saskatchewan
and Manitoba, and in the Northwest Territories.  We also have minor
proved plus probable reserves interests in the United States in the States of
Montana, Wyoming and North Dakota.
  Major
Operating Regions
  Our
production and reserves are attributed to more than 400 producing
properties.  No single property accounts for more than 10 percent
of our proved plus probable reserves.  Penn West's operations are
managed based on five major operating regions:  (i) Southern District,
(ii) Central District, (iii) Eastern District, (iv) NW Alberta District, and (v)
Northern District.  The following table shows our reported average
daily production in 2008 and proved plus probable reserves, as at
December 31, 2008, by major operating regions.  These major
operating regions represented approximately 100 percent of our average daily
production in 2008 and approximately 100 percent of our total gross proved plus
probable reserves (based on forecast cost and price assumptions) as assigned by
GLJ and Sproule in the Engineering Reports.
   11
  Average
      Daily Production
                  in
      2008
                
                
                Proved
      Plus Probable Gross Reserves
                  as
      at December 31, 2008Crude
      Oil and NGLs
                  (bbl/d)
                
                
                Natural
      Gas
                  (MMcf/d)
                
                
                Total
                  Oil
      Equivalent
                  (boe/d)
                
                
                Crude
      Oil and NGLs
                  (MMbbl)
                
                
                Natural
      Gas
                  (Bcf)
                
                
                Total
                  Oil
      Equivalent
                  (MMboe)
                
                
                Undeveloped
                  Land
                  as
      at December 31, 2008
                  (000
      net acres)Southern
                
                
                29,597
                
                
                
                58
                
                
                
                39,331
                
                
                
                140
                
                
                
                231
                
                
                
                178
                
                
                
                826Eastern
                
                
                24,730
                
                
                
                46
                
                
                
                32,468
                
                
                
                88
                
                
                
                99
                
                
                
                105
                
                
                
                356Central
                
                
                30,721
                
                
                
                207
                
                
                
                65,149
                
                
                
                157
                
                
                
                620
                
                
                
                261
                
                
                
                435NW
      Alberta
                
                
                18,783
                
                
                
                35
                
                
                
                24,529
                
                
                
                84
                
                
                
                114
                
                
                
                103
                
                
                
                571Northern
                
                
                3,921
                
                
                
                144
                
                
                
                27,985
                
                
                
                14
                
                
                
                412
                
                
                
                82
                
                
                
                1,035Total
                
                
                107,752
                
                
                
                490
                
                
                
                189,462
                
                
                
                483
                
                
                
                1,476
                
                
                
                729
                
                
                
                3,22357%
      of
                  daily
                  production
                
                
                43%
      of
                  daily
                  production
                
                
                
                
                
                
                66%
      of
                  total
                  reserves
                
                
                34%
      of
                  total
                  reserves
   The
following map outlines Penn West's five major operating regions as at December
31, 2008:
  
  The
following is a description of our principal oil and natural gas properties and
our related operations and activities by major operating region as at
December 31, 2008.   Information in respect of gross and net
acres and well counts is as at December 31, 2008, and information in
respect of production is for the year ended December 31, 2008 except where
indicated otherwise.  Due to the fact that we have been active at
acquiring additional interests in our principal properties, the working interest
share and interest in gross and net acres and wells as at December 31, 2008
may not directly correspond to the stated production for the year, which only
includes production since the date the interests were acquired by
us.  The estimates of
reserves and future net revenue for individual properties may not reflect the
same confidence level as estimates of reserves and future net revenue for all
properties, due to the application of statistical methods of aggregating
individual properties.
   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 2008, production in this district averaged 39,300 boe/d,
comprised of 29,600 bbl/d of crude oil and natural gas liquids and 58 MMcf/d of
natural gas.
  As at
December 31, 2008, Penn West had a land position of approximately 2.1 million
net acres in the Southern District.  In 2008, capital investment by
Penn West in this district was approximately $340 million.  Penn West
drilled 72 new wells in the Southern District in 2008.  In 2009, Penn
West plans overall capital expenditures to total about $190 million for the
Southern District.
  In
Southwest Saskatchewan, the predominant play for Penn West is the Leitchville
(Lower Shaunavon horizon) tight oil play.  This is an unconventional,
"resource" play that has been unlocked by multi-stage horizontal fracture
technology.  In 2008, Penn West drilled 25 wells in the Lower
Shaunavon horizon.  In 2009, Penn West expects to drill another 20 to
25 wells to further develop and expand the play.
  In
Southeast Saskatchewan, Penn West has been active on a number of
fronts.  In 2008, our focus was on land acquisition to increase Penn
West's position on the tight oil play in the Bakken pool and to develop a
strategy to expand Penn West's knowledge and position on the emerging Torquay
play to the eastern edges of the Williston Basin.  Also in 2008, we
worked on optimization opportunities in Penn West's legacy asset base and
participated in the Weyburn unit operated by EnCana Corporation, which is
currently under CO2 flood for
enhanced oil recovery.  Penn West holds a 21% interest in this
unit.  We plan total capital expenditures of approximately $70 million
for Southeast Saskatchewan in 2009.
  In
Southern Alberta, Penn West drilled 38 wells in 2008, targeting mainly the
Colony and Mid-Mannville horizons.  In 2009, Penn West plans to drill
up to 45 additional wells in Southern Alberta.  We plan total capital
expenditures of approximately $63 million for Southern Alberta in
2009.
  Eastern
District
  The
Eastern District straddles the Saskatchewan and Alberta border and is just north
of the Southern District.  This district contains most of Penn West's
heavy oil properties.  The Eastern District is characterized by
multi-zone crude oil potential.  In 2008, production in this district
averaged 32,500 boe/d, comprised of 24,700 bbl/d of crude oil and natural gas
liquids and 46 MMcf/d of natural gas.
  As at
December 31, 2008, Penn West had a land position of approximately 1.0 million
net acres in the Eastern District.  In 2008, capital investment by
Penn West in the Eastern District was approximately $160 million with 56 new
wells drilled.  In 2009, Penn West expects overall capital
expenditures to total about $65 million for the Eastern District.
  A major
property for Penn West in the Eastern District is Dodsland.  In 2008,
Penn West drilled its first horizontal injector well in the Dodsland
area.  In 2009, Penn West plans to drill one additional injector well
and two horizontal producer wells in this area.  We expect total
capital expenditures of approximately $10 million for the Dodsland area in 2009.
  Central
District
  The
Central District runs from the eastern border of the Eastern District and
stretches from northeast of Edmonton to just north of Calgary and runs west to
the foothills of Alberta.  This district is Penn West's largest
district in terms of production.  The district is characterized by
legacy light oil assets and gas pools with multi-zone potential.  In
2008, production in this district averaged about 65,100 boe/d comprised of
30,700 bbl/d of crude oil and natural gas liquids and 207 MMcf/d of natural
gas
  As at
December 31, 2008, Penn West had a land position of approximately 1.6 million
net acres in the Central District.  In 2008, Penn West drilled 38 new
wells in this district and made a capital investment of approximately $208
million.  In 2009, Penn West expects overall capital expenditures to
total about $120 million for the Central District.
   13
  The
Pembina area is a key property for Penn West in the Central District and
multi-stage horizontal fracture technology is being used to drill both producing
wells and injectors to further enhance recovery in the Pembina
area.  Penn West has also initiated a CO2 flood
pilot project for enhanced oil recovery in the Pembina area and operates at
Joffre, Alberta what is currently Alberta's only commercial CO2 flood
enhanced oil recovery project.  Penn West plans to continue this
CO2
flood project in 2009.
  Another
important property for Penn West in the Central District is the Wimborne area,
which is a light oil play in central Alberta.  Penn West anticipates
opportunities in terms of enhanced oil recovery using water floods in this area,
as well as drilling opportunities in certain parts of the area.  In
2009, Penn West plans to formulate and begin to implement a long-term
development plan for this asset.
  Another
important asset for Penn West in the Central District is the Willesden Green
property, which is a legacy asset located west of Red Deer,
Alberta.  The Willesden Green area is characterized by multi-zone
light oil and gas opportunities.  In 2008, Penn West drilled a new gas
well in the area and in 2009, we plan to acquire seismic in order to identify
future drilling locations.
  The
Minnehik Buck Lake unit, a sour gas property operated by Penn West, is another
important asset for Penn West in the Central District.  The unit
currently consists of 17 producing gas wells and includes a sour gas processing
plant.  A major sulphur plant turnaround is scheduled for the third
quarter of 2011.  Penn West is currently evaluating alternatives to
safely and cost-effectively handle the hydrogen sulfide and CO2 components
of the gas stream.
  NW
Alberta District
  The NW
Alberta District is located north of Edmonton and is bounded by the British
Columbia border to the west.  This district is predominantly a light
oil district characterized by large oil-in-place "legacy assets".  Due
to the nature of the asset base, Penn West's focus in this district has been on
enhanced oil recovery.  In 2008, production in this district averaged
about 24,500 boe/d, comprised of 18,800 bbl/d of crude oil and natural gas
liquids and 34 MMcf/d of natural gas.
  As at
December 31, 2008, Penn West had a land position of approximately 1.1 million
net acres in the NW Alberta District.  In 2008, Penn West drilled 34
new wells in this district and made a capital investment of approximately $224
million.  In 2009, Penn West expects overall capital expenditures to
total about $48 million for the NW Alberta District.
  An
important asset for Penn West in the NW Alberta District is the Seal area, a
heavy oil play on oil sands leases, located in the Peace River area of north
central Alberta.  In 2008, production from the Seal area averaged
about 2,000 boe/d.  In 2009, Penn West has postponed its development
program in the Seal area due to low commodity prices.  Penn West
expects to resume its capital program in the Seal area when commodity prices
recover.
  The Swan
Hills properties are another important asset for Penn West in the NW Alberta
District.  The Swan Hills properties are light oil in place "legacy"
assets in the Devonian reef complex of the Beaver Hill Lake formation and
provide some of Penn West's longest-life reserves.  In 2008, Penn West
implemented a CO2 flood
pilot project for enhanced oil recovery in the South Swan Hills unit, which Penn
West operates.  In 2009, Penn West plans to evaluate long-term
development plans aimed at increasing recovery factors through optimization of
current water floods and infill drilling opportunities in the Swan Hills
area.
  Northern
District
  The
Northern District includes northeastern British Columbia, the northwestern
corners of Alberta (including the Peace River Arch) and southwestern Northwest
Territories.  This district is characterized primarily by natural gas
with multi-zone production.  In 2008, this district averaged about
28,000 boe/d comprised of 3,900 bbl/d of crude oil and natural gas liquids and
144 MMcf/d of natural gas.
  As at
December 31, 2008, Penn West had a land position of approximately 1.8 million
net acres in the Northern District.  In 2008, Penn West drilled six
new wells and made a capital investment of approximately $113
million.  In 2009, Penn West expects overall capital expenditures to
total about $43 million for the Northern District.
   14
  In
northeast British Columbia, Penn West is testing and evaluating the economic
potential of a shale gas play.  In 2008, Penn West drilled three wells
to collect data on this play.  In 2009, Penn West has slowed its
development program in this play due to low commodity prices, but we expect to
continue evaluation of the play with one well planned in 2009 and expected total
capital expenditures of $10 million for the
year.
  An
important asset for Penn West, located in the most northern portion of the
Northern District, is the Wildboy area, a winter-only access property in
northern British Columbia, which targets natural gas production.  The
Wildboy area is served by a natural gas plant and sales pipeline that is 100%
owned and operated by Penn West and connects to the TransCanada pipeline system
in Alberta.
  Another
important property for Penn West in the Northern District is our position in the
Montney natural gas play located near Dawson Creek, British
Columbia.  In 2009, Penn West plans to drill two horizontal wells and
expects total capital expenditures of $10 million for the Montney
play.
  
 Additional
Information
  None of
our important properties, plants, facilities or installations are subject to any
material statutory or other mandatory relinquishments, surrenders, back-ins or
changes in ownership.
  We do not
have any material properties to which reserves have been attributed which are
capable of producing but which are not producing.  For a discussion of
our properties to which reserves have been attributed and which are capable of
producing but which are not producing, see "Additional Information Relating to
Reserves Data – Undeveloped Reserves" above.
  Oil
And Gas Wells
  The
following table sets forth the number and status of wells in which we had a
working interest as at December 31, 2008.
  Producing
              
              
              Non-Producing
              
              
              TotalOil
              
              
              GasGross
              
              
              Net
              
              
              Gross
              
              
              Net
              
              
              Gross
              
              
              Net
              
              
              Gross
              
              
              NetAlberta
              
              
              10,114
              
              
              
              5,669
              
              
              
              9,756
              
              
              
              4,047
              
              
              
              7,007
              
              
              
              3,851
              
              
              
              26,877
              
              
              
              13,567British
      Columbia
              
              
              145
              
              
              
              49
              
              
              
              984
              
              
              
              474
              
              
              
              428
              
              
              
              154
              
              
              
              1,557
              
              
              
              677Saskatchewan
              
              
              7,740
              
              
              
              5,094
              
              
              
              1,176
              
              
              
              655
              
              
              
              3,255
              
              
              
              1,688
              
              
              
              12,171
              
              
              
              7,437Manitoba
              
              
              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
              
              
              18,738
              
              
              
              11,159
              
              
              
              12,226
              
              
              
              5,301
              
              
              
              11,012
              
              
              
              5,828
              
              
              
              41,976
              
              
              
              22,288
  Properties
with no Attributed Reserves
  The
following table sets out the unproved properties in which we have an interest as
at December 31, 2008.
   15
  Unproved
      Properties
                  (000s
      of Acres)Gross
              
              
              NetAlberta
              
              
              2,208
              
              
              
              1,793British
      Columbia
              
              
              756
              
              
              
              569Saskatchewan
              
              
              755
              
              
              
              662Manitoba
              
              
              153
              
              
              
              147Northwest
      Territories
              
              
              91
              
              
              
              18Wyoming
              
              
              16
              
              
              
              9Montana
              
              
              3
              
              
              
              2North
      Dakota
              
              
              28
              
              
              
              23Total
              
              
              4,010
              
              
              
              3,223
  We
currently have no material work commitments on these lands.  The
primary lease or extension term on approximately 532,323 net acres of
unproved property will expire by December 31, 2009.  The right to
explore, develop and exploit these leases will be surrendered unless we qualify
them for continuation based on existing production, drilling or technical
mapping.
  Tax
Horizon
  Under
currently enacted legislation, as a result of our tax structure, taxable income
is transferred from our Operating Entities to the Trust and from the Trust to
Unitholders.  This is primarily accomplished through the deduction by
our Operating Entities of the royalties on underlying oil and gas properties and
the deduction of interest on the Internal Notes.  The terms of the
Trust Indenture require the Trust to distribute all of its taxable income,
therefore, it is currently expected that no income tax liability will be
incurred provided we maintain this organizational structure.  To the
extent that taxable income is retained in our Operating Entities to fund capital
expenditures or repay bank debt, it is possible that income taxes could be
payable at some time in the future.
  The
legislation implementing the SIFT Tax received Royal assent on June 22,
2007 with the result that commencing January 1, 2011 taxes could be
exigible in the Trust as certain distributions will no longer be a deduction in
the calculation of its taxable income. For more information on
the SIFT Tax, see "General Development of the Business – History and Development
– Year Ended December 31, 2006 – Changes to Taxation of Income Trusts" and "Risk
Factors".
  The most
important variables that will determine the level of cash taxes incurred by us
in a given year will be the price of crude oil and natural gas, our capital
spending levels and the amount of tax pools available to us.  Assuming
the implementation of the SIFT Tax on January 1, 2011 and that we do not change
our current organizational structure, we estimate that we would not be required
to pay income taxes until at least the 2014 taxation year.  However,
if crude oil and natural gas prices were to strengthen beyond the levels
anticipated by the current forward market, our tax pools would be utilized more
quickly and we may experience higher than expected cash taxes or payment of such
taxes in an earlier time period. However, we emphasize that it is difficult to
give guidance on future taxability as we operate within an industry where
various factors constantly change our outlook, including factors such as
acquisitions, divestments, capital spending levels, distribution levels and
commodity price changes.
  Capital
Expenditures
  The
following table summarizes capital expenditures (net of incentives and net of
certain proceeds) related to our activities for the year ended December 31,
2008, irrespective of whether such costs were capitalized or charged to expense
when incurred.
   16
  2008
                  MM$Property
      AcquisitionsProved
    Properties
              
              
              (50
              )Unproved
    Properties
              
              
              128Exploration
      Costs(1)
              
              
              140Development
      Costs(2)
              
              
              780Corporate
      Costs
              
              
              47Capital
      Expenditures
              
              
              1,045Corporate
      Acquisitions
              
              
              5,525Total
      Expenditures
              
              
              6,570
  Notes:
  (1)
              Costs
      of land acquired, geological and geophysical capital expenditures and
      drilling costs for 2008 exploration wells
  drilled.
  (2)
              Includes
      equipping and facilities capital
expenditures.
  Exploration
and Development Activities
  The
following table sets forth the gross and net exploratory and development wells
that we participated in during the year ended December 31,
2008.
  Exploratory
      Wells
              
              
              Development
      WellsGross
              
              
              Net
              
              
              Gross
              
              
              NetOil
              
              
              20
              
              
              
              12
              
              
              
              259
              
              
              
              124Natural
      Gas
              
              
              39
              
              
              
              27
              
              
              
              185
              
              
              
              76Service
              
              
              8
              
              
              
              8
              
              
              
              32
              
              
              
              30Dry
              
              
              4
              
              
              
              4
              
              
              
              10
              
              
              
              7Total
              
              
              71
              
              
              
              51
              
              
              
              486
              
              
              
              237
  We
currently estimate that our capital expenditures in 2009 will be toward the
lower end of our $600 million to $825 million 2009 capital expenditure
budget in order to execute our current 2009 capital programs.  The
primary components of our programs are described under the heading "Other Oil
and Gas information – Description of Our Properties, Operations and Activities
in Our Major Operating Regions".
  Production
Estimates
  The
following table sets out the volume of our production estimated for the year
ended December 31, 2009 which is reflected in the estimates of gross proved
reserves and gross probable reserves disclosed in the tables contained under
"Disclosure of Reserves Data" above.
  Light
      and Medium Oil
              Heavy
      Oil
              Natural
      Gas
              Natural
      Gas Liquids
              Total
      Oil Equivalent(bbl/d)
              (bbl/d)
              (Mcf/d)
              (bbl/d)
              (boe/d)Gross
              
              
              Net
              
              Gross
              
              
              Net
              
              Gross
              
              
              Net
              
              Gross
              
              
              Net
              
              Gross
              
              
              NetProved
      Producing
              63,520
              
              
              54,172
              
              23,354
              
              
              21,026
              
              418,640
              
              
              345,643
              
              10,459
              
              
              7,329
              
              167,106
              
              
              140,133Proved
      Developed Non-
                Producing
              972
              
              
              672
              
              1,043
              
              
              899
              
              19,580
              
              
              14,603
              
              351
              
              
              244
              
              5,629
              
              
              4,249Proved
      Undeveloped
              2,379
              
              
              2,105
              
              591
              
              
              522
              
              5,283
              
              
              4,119
              
              40
              
              
              32
              
              3,891
              
              
              3,345Total
      Proved
              66,870
              
              
              56,949
              
              24,988
              
              
              22,446
              
              443,503
              
              
              364,365
              
              10,850
              
              
              7,605
              
              176,626
              
              
              147,727Total
      Probable
              3,214
              
              
              2,749
              
              2,067
              
              
              1,724
              
              29,090
              
              
              22,448
              
              573
              
              
              402
              
              10,702
              
              
              8,616Total
      Proved Plus
                Probable
              70,084
              
              
              59,698
              
              27,055
              
              
              24,169
              
              472,594
              
              
              386,813
              
              11,423
              
              
              8,007
              
              187,328
              
              
              156,344
   17
  No one
field accounts for more thanthreepercent of the estimated
production disclosed above.  For more information, see "Other Oil and
Gas Information – Description of Our Properties, Operations and Activities
in Our Major Operating Regions".
  Production
History
  The
following table summarizes certain information in respect of our production,
product prices received, royalties paid, production costs and resulting netback
for the periods indicated below:
  Quarter
      Ended 2008
              
              
              Year
      EndedMar.
      31
              
              
              June
      30
              
              
              Sept.
      30
              
              
              Dec.
      31
              
              
              Dec.
      31, 2008Average
      Daily Production(1)Light
      and Medium Crude Oil (bbl/d)
              
              
              71,560
              
              
              
              71,496
              
              
              
              68,959
              
              
              
              68,219
              
              
              
              70,050Heavy
      Oil (bbl/d)
              
              
              27,338
              
              
              
              27,460
              
              
              
              28,136
              
              
              
              26,529
              
              
              
              27,366Gas
      (MMcf/d)
              
              
              500
              
              
              
              487
              
              
              
              500
              
              
              
              476
              
              
              
              490NGLs
      (bbl/d)
              
              
              10,118
              
              
              
              10,461
              
              
              
              9,803
              
              
              
              10,896
              
              
              
              10,320Combined
      (boe/d)
              
              
              192,291
              
              
              
              190,515
              
              
              
              190,177
              
              
              
              184,908
              
              
              
              189,462Average
      Net Production Prices ReceivedLight
      and Medium Crude Oil ($/bbl)
              
              
              92.07
              
              
              
              116.33
              
              
              
              114.32
              
              
              
              55.02
              
              
              
              94.66Heavy
      Oil ($/bbl)
              
              
              66.64
              
              
              
              93.12
              
              
              
              98.07
              
              
              
              38.67
              
              
              
              74.55Gas
      ($/Mcf)
              
              
              7.98
              
              
              
              10.20
              
              
              
              8.49
              
              
              
              7.03
              
              
              
              8.43NGLs
      ($/bbl)
              
              
              65.43
              
              
              
              81.49
              
              
              
              83.22
              
              
              
              45.53
              
              
              
              68.45Combined
      ($/boe)
              
              
              68.35
              
              
              
              87.60
              
              
              
              83.23
              
              
              
              46.79
              
              
              
              71.65Royalties
      PaidLight
      and Medium Crude Oil ($/bbl)
              
              
              14.34
              
              
              
              19.20
              
              
              
              19.10
              
              
              
              8.70
              
              
              
              15.37Heavy
      Oil ($/bbl)
              
              
              9.98
              
              
              
              13.50
              
              
              
              14.80
              
              
              
              5.80
              
              
              
              11.09Gas
      ($/Mcf)
              
              
              1.76
              
              
              
              2.02
              
              
              
              1.89
              
              
              
              1.60
              
              
              
              1.84NGLs
      ($/bbl)
              
              
              17.30
              
              
              
              18.99
              
              
              
              21.11
              
              
              
              12.57
              
              
              
              17.38Combined
      ($/boe)
              
              
              12.25
              
              
              
              15.35
              
              
              
              15.23
              
              
              
              8.89
              
              
              
              12.95Production
      Costs(2)(3)Light
      and Medium Crude Oil ($/bbl)
              
              
              16.51
              
              
              
              16.75
              
              
              
              17.79
              
              
              
              18.74
              
              
              
              17.43Heavy
      Oil ($/bbl)
              
              
              12.87
              
              
              
              12.94
              
              
              
              13.63
              
              
              
              14.04
              
              
              
              13.37Gas
      ($/Mcf)
              
              
              1.15
              
              
              
              1.19
              
              
              
              1.26
              
              
              
              1.34
              
              
              
              1.23NGLs
      ($/bbl)
              
              
              12.84
              
              
              
              13.02
              
              
              
              13.84
              
              
              
              14.53
              
              
              
              13.57Combined
      ($/boe)
              
              
              11.64
              
              
              
              11.91
              
              
              
              12.49
              
              
              
              13.22
              
              
              
              12.31TransportationLight
      and Medium Crude Oil ($/bbl)
              
              
              -
              
              
              
              -
              
              
              
              -
              
              
              
              -
              
              
              
              -Heavy
      Oil ($/bbl)
              
              
              0.08
              
              
              
              0.06
              
              
              
              0.06
              
              
              
              0.05
              
              
              
              0.06Gas
      ($/Mcf)
              
              
              0.18
              
              
              
              0.19
              
              
              
              0.18
              
              
              
              0.19
              
              
              
              0.19NGLs
      ($/bbl)
              
              
              -
              
              
              
              -
              
              
              
              -
              
              
              
              -
              
              
              
              -Combined
      ($/boe)
              
              
              0.48
              
              
              
              0.49
              
              
              
              0.49
              
              
              
              0.49
              
              
              
              0.49(Gain)/Loss
      on Risk Management ContractsLight
      and Medium Crude Oil ($/bbl)
              
              
              9.35
              
              
              
              25.26
              
              
              
              25.48
              
              
              
              (5.91
              )
              
              
              13.64Heavy
      Oil ($/bbl)
              
              
              -
              
              
              
              -
              
              
              
              -
              
              
              
              -
              
              
              
              -Gas
      ($/Mcf)
              
              
              (0.03
              )
              
              
              0.99
              
              
              
              0.93
              
              
              
              (0.37
              )
              
              
              0.39NGLs
      ($/bbl)
              
              
              -
              
              
              
              -
              
              
              
              -
              
              
              
              -
              
              
              
              -Combined
      ($/boe)
              
              
              3.41
              
              
              
              12.01
              
              
              
              11.69
              
              
              
              (3.12
              )
              
              
              6.05
  18
  Quarter
      Ended 2008
                
                
                Year
      EndedMar.
      31
                
                
                June
      30
                
                
                Sept.
      30
                
                
                Dec.
      31
                
                
                Dec.
      31, 2008Netback
      Received(4)Light
      and Medium Crude Oil ($/bbl)
                
                
                51.87
                
                
                
                55.12
                
                
                
                51.95
                
                
                
                33.49
                
                
                
                48.22Heavy
      Oil ($/bbl)
                
                
                43.71
                
                
                
                66.62
                
                
                
                69.58
                
                
                
                18.78
                
                
                
                50.03Gas
      ($/Mcf)
                
                
                4.92
                
                
                
                5.81
                
                
                
                4.23
                
                
                
                4.27
                
                
                
                4.78NGLs
      ($/bbl)
                
                
                35.29
                
                
                
                49.48
                
                
                
                48.27
                
                
                
                18.43
                
                
                
                37.50Combined
      ($/boe)
                
                
                40.57
                
                
                
                47.84
                
                
                
                43.33
                
                
                
                27.31
                
                
                
                39.85
  Notes:
  (1)
              Before
      deduction of royalties.
  (2)
              Operating
      expenses are composed of direct costs incurred to operate both oil and gas
      wells.  A number of assumptions are required to allocate these
      costs between oil, natural gas and natural gas liquids
      production.
  (3)
              Operating
      recoveries associated with operated properties are charged to operating
      costs and accounted for as a reduction to general and administrative
      costs.
  (4)
              Netbacks
      are calculated by subtracting royalties, operating costs, transportation
      costs and losses/gains on commodity and foreign exchange contracts from
      revenues.
  Marketing
Arrangements
  Our
marketing approach incorporates the following primary objectives:
  ·
              Ensure
      security of market and avoid production shut-ins due to marketing
      constraints by dealing with end-users or regionally strategic
      counterparties wherever possible.
  ·
              Ensure
      protection of our receivables by dealing only with credit worthy
      counterparties who have been subjected to regular credit
      reviews.
  ·
              Ensure
      competitive pricing by managing pricing exposures through a portfolio of
      various terms and geographic basis.
  ·
              Ensure
      optimization of netbacks through careful management of transportation
      obligations, facility utilization levels, blending opportunities and
      emulsion handling.
  Natural
Gas Marketing
  In 2008,
we received an average price from the sale of natural gas, before adjustments
for hedging activities, of $8.43/Mcf compared to $6.85/Mcf realized in
2007.  Approximately 87 percent of our natural gas sales are marketed
directly with the balance of natural gas sales marketed in aggregator
pools.  We continue to maintain a significant weighting to the Alberta
market as this market offers a premium netback relative to most other
indices.  In addition to maximizing netbacks, the current portfolio
approach also enhances our operational flexibility to pursue higher netback
opportunities as they become available.
  We
continue to conservatively manage our transportation
costs.  Transportation on all pipelines is closely balanced to supply,
and market commitments related to export transportation represented less than
two percent of sales.
  Oil
and Liquids Marketing
  In terms
of our entire liquids production, approximately 65% is light and medium oil, 25%
is conventional heavy oil and 10% is NGLs. In regards specifically to crude oil,
our average quality is 29 degrees API on a corporate average level, which is
comprised of an average quality for our light and medium oil of 35 degrees API
and an average quality for our conventional heavy oil of 16 degrees
API.
   19
  To reduce
risk, we market the majority of our production at the lease level on varying
term contracts and actively manage our heavy oil supply by finding opportunities
to optimize netbacks through blending, trucking and proprietary handling of
emulsion. Blending costs are also controlled through the use of proprietary
condensate supply.
  The
following table summarizes the net product price received for our production of
conventional light and medium oil (including NGLs) and our conventional heavy
oil, before adjustments for hedging activities, for the periods
indicated:
  2008
              
              
              2007Light
      and Medium Oil
              
              
              Heavy
      Oil
              
              
              Light
      and Medium Oil
              
              
              Heavy
      OilQuarter
      ended
              
              ($/bbl)
              
              
              ($/bbl)
              
              
              ($/bbl)
              
              
              ($/bbl)March
      31
              
              
              92.07
              
              
              
              66.64
              
              
              
              60.93
              
              
              
              41.03June
      30
              
              
              116.33
              
              
              
              93.12
              
              
              
              66.57
              
              
              
              42.45September
      30
              
              
              114.32
              
              
              
              98.07
              
              
              
              74.49
              
              
              
              48.75December
      31
              
              
              55.02
              
              
              
              38.67
              
              
              
              78.20
              
              
              
              48.69
  Forward
Contracts
  We are
exposed to market risks resulting from fluctuations in commodity prices, foreign
exchange rates and interest rates in the normal course of operations. In
accordance with policies approved by our Board of Directors, we may, from time
to time, manage these risks through the use of swaps, collars or other financial
instruments.  Commodity price risk may be hedged up to a maximum of 50
percent of forecast sales volumes, net of royalties, for the balance of any
current year and one year following and up to 25 percent of forecast sales
volumes, net of royalties, for one additional year thereafter.  This
policy is reviewed by management and our Board of Directors from time to time
and amended as necessary.
  We are
also exposed to losses in the event of default by the counterparties to these
derivative instruments. We manage this risk by diversifying our hedging
portfolio among a number of financially sound counterparties. For information in
relation to marketing arrangements, see "Other Oil and Gas Information –
Marketing Arrangements".
 
 As at
December 31, 2008, we were not bound by any agreement (including a
transportation agreement), directly or through an aggregator, under which we may
be precluded from fully realizing, or may be protected from the full effect of,
future market prices for oil or natural gas, except for agreements disclosed by
us as financial instruments in accordance with Section 3861 of the CICA
Handbook, or as contractual obligations or commitments in accordance with
Section 3280 of the CICA Handbook.  For information regarding our
outstanding financial instruments as at December 31, 2008, see Note 13 (Risk
management) to our audited annual consolidated financial statements as at and
for the year ended December 31, 2008, which have been filed on SEDAR at www.sedar.com.
  Our
transportation obligations and commitments for future physical deliveries of
crude oil and natural gas do not exceed our expected related future production
from our proved reserves, estimated using forecast prices and
costs.
  20
  APPENDIX
B
  MANDATE
OF THE AUDIT COMMITTEE
  Role
and Objective
  The Audit
Committee (the "Committee") is a committee of
the board of directors of Penn West Petroleum Ltd. (the "Company"), administrator of
Penn West Energy Trust (the "Trust"), to which the board
has delegated its responsibility for oversight of the integrity of the Trust's
consolidated financial statements, the Trust's compliance with legal and
regulatory requirements, the independent auditor's qualifications and
independence, and the performance of the Trust's internal audit function, if
any.  The objectives of the Committee, with respect to Company and the
Trust (hereinafter collectively referred to as "Penn West"), are as
follows:
  ·
              To
      assist the Board in meeting its responsibilities (especially for
      accountability) in respect of the preparation and disclosure of the
      consolidated financial statements of the Trust and related
      matters;
  ·
              To
      provide better communication between directors and independent
      auditors;
  ·
              To
      assist the Board in meeting its responsibilities regarding the oversight
      of the independent auditor's qualifications and
    independence;
  ·
              To
      assist the Board in meeting its responsibilities regarding the oversight
      of the credibility, integrity and objectivity of financial
      reports;
  ·
              To
      strengthen the role of the non-management directors by facilitating
      discussions between directors on the Committee, management and independent
      auditors;
  ·
              To
      assist the Board in meeting its responsibilities regarding the oversight
      of the performance of the Company's independent auditors and internal
      audit function, if any; and
  ·
              To
      assist the Board in meeting its responsibilities regarding the oversight
      of the Company's compliance with legal and regulatory
      requirements.
  Mandate
and Responsibilities of Committee
  ·
              It
      is the responsibility of the Committee to satisfy itself on behalf of the
      Board that the Company's internal control systems are sufficient to
      reasonably ensure that:
  ·
              controllable,
      material business risks are identified, monitored and mitigated where it
      is determined cost effective to do
so;
  ·
              internal
      controls over financial reporting are sufficient to meet the requirements
      under National Instrument 52-109 and the United States Securities
      Exchange Act of 1934, as amended;
and
  ·
              legal,
      ethical and regulatory requirements are complied
  with.
  ·
              It
      is a primary responsibility of the Committee to review the annual and
      quarterly financial statements of the Trust prior to their submission to
      the board of directors for approval.  The process should include
      but not be limited to:
  ·
              reviewing
      changes in accounting principles, or in their application, which may have
      a material impact on the current or future years' financial
      statements;
  ·
              reviewing
      significant accruals, reserves or other estimates such as the ceiling test
      calculation;
  ·
              reviewing
      accounting treatment of unusual or non-recurring
    transactions;
  ·
              reviewing
      the Trust's status as a "mutual fund trust" under the Income Tax Act
      (Canada);
   
  ·
              ascertaining
      compliance with covenants under loan agreements and Trust
      Indenture;
  ·
              reviewing
      adequacy of the asset retirement
obligations;
  ·
              reviewing
      disclosure requirements for commitments and
  contingencies;
  ·
              reviewing
      adjustments raised by the independent auditors, whether or not included in
      the financial statements;
  ·
              reviewing
      unresolved differences between management and the independent auditors, if
      any;
  ·
              obtaining
      reasonable explanations of significant variances with comparative
      reporting periods; and
  ·
              determine through inquiry if
      there are any related party transactions and ensure the nature and
      extent of such transactions
      are properly disclosed.
  ·
              The
      Committee is to review, discuss and recommend for approval by the Board
      the annual and quarterly financial statements and related information
      included in prospectuses, management discussion and analysis (MD&A),
      information circular-proxy statements and annual information forms (AIF),
      prior to recommending board
approval.
  ·
              Discuss
      the Trust's quarterly results press releases, as well as financial
      information and earnings guidance provided to analysts and rating agencies
      (provided that the Committee is not required to review and discuss
      investor presentations that do not contain financial information or
      earnings guidance that has not previously been generally disclosed to the
      public).
  ·
              With
      respect to the appointment of independent auditors by the Board, the
      Committee shall:
  ·
              on
      an annual basis, the Committee shall review and discuss with the auditors
      all relationships the auditors have with the Trust and the Company to
      determine the auditors' independence.  In addition, the
      Committee will ensure the rotation of partners on the audit engagement
      team in accordance with applicable law and, in order to ensure continuing
      auditor independence, consider the rotation of the audit firm
      itself;
  ·
              be
      directly responsible for appointing, compensating, retaining and
      overseeing the work of the independent auditors engaged for the purpose of
      issuing an auditors' report or performing other audit, review or attest
      services for the Trust, including the resolution of disagreements between
      management and the independent auditor regarding financial reporting, and
      the independent auditors shall report directly to the
      Committee;
  ·
              review
      and evaluate the performance of the lead partner of the independent
      auditors;
  ·
              review
      the basis of management's recommendation for the appointment of
      independent auditors and recommend to the board appointment of independent
      auditors and their compensation;
  ·
              review
      the terms of engagement and the overall audit plan (including the
      materiality levels to be applied) of the independent auditors, including
      the appropriateness and reasonableness of the auditors'
    fees;
  ·
              when
      there is to be a change in auditors, review the issues related to the
      change and the information to be included in the required notice to
      securities regulators of such change;
and
  ·
              review
      and pre-approve any audit and permitted non-audit services to be provided
      by the independent auditors' firm and consider the impact on the
      independence of the auditors.
  ·
              At
      least annually, obtaining and reviewing the report by the independent
      auditors describing the independent auditors' internal quality control
      procedures, any material issues raised by the most recent interim
      quality-control review, or peer review, of the independent auditors, or by
      any inquiry or investigation by governmental or professional authorities,
      within the preceding five years, respecting one or more independent audits
      carried out by the independent auditors, and any steps taken to deal with
      any such issues.
  ·
              Review
      with the independent auditors (and internal auditors, if any) their
      assessment of the internal controls of the Company, their written reports
      containing recommendations for improvement, and management's response and
      follow-up to any identified weaknesses.  The Committee shall
      also review annually with the independent auditors
  2
  their
      plan for their audit and, upon completion of the audit, their reports upon
      the financial statements of Penn West and its
  subsidiaries.
 ·
              At
      least annually, obtaining and reviewing a report by the independent
      auditors describing (i) all critical accounting policies and practices
      used by the Trust, (ii) all alternative accounting treatments of financial
      information within generally accepted accounting principles related to
      material items that have been discussed with management, including the
      ramifications of the use of such alternative treatments and disclosures
      and the treatment preferred by the accounting firm, and (iii) other
      material written communications between the accounting firm and management
      of Penn West.
  ·
              Obtain
      assurance from the independent auditors that disclosure to the Committee
      is not required pursuant to the provisions of the United States Securities
      Exchange Act of 1934, as amended, regarding the discovery by the
      independent auditors of illegal
acts.
  ·
              Pre-approve
      the completion of any audit and permitted non-audit services by the
      independent auditors and determine which non-audit services the
      independent auditor is prohibited from providing.  The Committee
      may delegate to one or more members of the Committee authority to
      pre-approve non-audit services in satisfaction of this requirement and if
      such delegation occurs, the pre-approval of non-audit services by the
      Committee member to whom authority has been delegated must be presented to
      the Committee at its first scheduled meeting following such
      pre-approval.  The Committee shall be entitled to adopt specific
      policies and procedures for the engagement of non audit services
      if:
  ·
              the
      pre-approval policies and procedures are detailed as to the particular
      service;
  ·
              the
      Committee is informed of each non-audit service so approved;
      and
  ·
              the
      procedures do not include delegation of the Committee's responsibilities
      to management.
  ·
              The
      Committee will satisfy the pre-approval requirement set forth in the above
      paragraph if:
  ·
              the
      aggregate amount of all non audit services that were not pre approved is
      reasonably expected to constitute no more than 5% of the total amount of
      fees paid by the Trust and its subsidiary entities to the auditors during
      the fiscal year in which the services are
  provided;
  ·
              the
      Trust or the subsidiary entity, as the case may be, did not recognize the
      services as non-audit services at the time of the
    engagement;
  ·
              the
      services are promptly brought to the attention of the Committee and
      approved, prior to completion of the audit, by the Committee or by one or
      more of its members to whom authority to grant such approvals has been
      delegated by the Committee; and
  ·
              Review,
      set and approve hiring policies relating to current and former staff of
      current and former independent
auditors.
  ·
              Review
      all public disclosure containing financial information before release
      (provided that the Committee is not required to review investor
      presentations that do not contain financial information or earnings
      guidance that has not previously been generally disclosed to the
      public).
  ·
              Review
      all pending litigation to ensure disclosures are sufficient and
      appropriate.
  ·
              Satisfy
      itself that adequate procedures are in place for the review of the Trust's
      public disclosure of financial information from the Trust's financial
      statements and periodically assess the adequacy of those
      procedures.
  ·
              Review
      and discuss major financial risk exposures and the steps management has
      taken to monitor and control such exposures.  Discuss guidelines
      and policies to govern the process by which risk assessment and management
      is undertaken.
  ·
              Establish
      procedures independent of management
for:
   4
  ·
              the
      receipt, retention and treatment of complaints received by the Trust
      regarding accounting, internal accounting controls, or auditing matters;
      and
  ·
              the
      confidential, anonymous submission by employees of the Trust of concerns
      regarding questionable accounting or auditing
  matters.
  ·
              Review
      any other matters required by law, regulation or stock exchange
      requirement, or that the Committee feels are important to its mandate or
      that the Board chooses to delegate to
it.
  ·
              Establish,
      review and update periodically a Code of Business Conduct and Ethics and
      the Code of Conduct for Senior Officers and Senior Financial Management
      and ensure that management has established systems to enforce these
      codes.
  ·
              Review
      management's monitoring of the Trust's compliance with the organization's
      Code of Business Conduct and Ethics and the Code of Conduct for Senior
      Officers and Senior Financial
Management.
  ·
              Review
      and discuss with the Chief Executive Officer, the Chief Financial Officer
      and the independent auditors, the matters required to be reviewed with
      those persons in connection with any certificates required by applicable
      laws, regulations or stock exchange requirements to be provided by the
      Chief Executive Officer and Chief Financial
  Officer.
  ·
              Review
      and discuss major issues regarding accounting principles and financial
      statement presentations, including any significant changes in the Trust's
      selection or application of accounting
  principles.
  ·
              Review
      and discuss major issues as to the adequacy of the Trust's internal
      controls and any special audit steps adopted in light of material control
      deficiencies.
  ·
              Review
      and discuss analyses prepared by management and/or the independent
      auditors setting forth significant financial reporting issues and
      judgments made in connection with the preparation of the financial
      statements, including analyses of the effects of alternative generally
      accepted accounting principles methods on the financial
      statements.
  ·
              Review
      and discuss the effect of regulatory and accounting initiatives, as well
      as off-balance sheet structures, on the Trust's financial
      statements.
  ·
              Review
      and discuss the type and presentation of information to be included in
      earnings press releases, paying particular attention to any use of "pro
      forma" or "adjusted" non-GAAP
information.
  Composition
  ·
              This
      Committee shall be composed of at least three individuals appointed by the
      Board from amongst its members, all of which members will be independent
      (within the meaning of (a) National Instrument 52-110 Audit Committees and
      (b) Sections 303A.02 and 303A.07(b) of the Corporate Governance Rules of
      the New York Stock Exchange) unless the Board determines to rely on an
      exemption in National Instrument
52-110.
  ·
              The
      Secretary to the Board shall act as Secretary of the
      Committee.
  ·
              A
      quorum shall be a majority of the members of the
  Committee.
  ·
              All
      of the members must be financially literate within the meaning of National
      Instrument 52-110 and Section 303A.07(a) of the Corporate Governance Rules
      of the New York Stock Exchange unless the Board has determined to rely on
      an exemption in National Instrument 52-110.  Being "financially
      literate" means members have the ability to read and understand a set of
      financial statements that present a breadth and level of complexity of
      accounting issues that are generally comparable to the breadth and
      complexity of issues that can reasonably be expected to be
  4
  raised
      by the Trust's financial statements.  In addition, at least one
      member of the Committee must have accounting or related financial
      management expertise, as the Board interprets such qualification in its
      business judgment.
 ·
              In
      connection with the appointment of the members of the Committee, the Board
      will determine whether any proposed nominee for the Committee serves on
      the audit committee of more than three public companies.  To the
      extent that any proposed nominee of PWPL serves on the audit committee of
      more than three public companies, the Board will make a determination as
      to whether such simultaneous services would impair the ability of such
      member to effectively serve on the Company's Audit Committee and will
      disclose such determination in the Trust's annual information circular and
      annual report on Form 40-F filed with the Securities and Exchange
      Commission.
  Meetings
  ·
              The
      Committee shall meet at least four times per year and/or as deemed
      appropriate by the Committee Chair.  As part of its job to
      foster open communication, the Committee should meet at least annually
      with management, internal auditors (if any) and the independent auditors
      in separate executive sessions to discuss any matters that the Committee
      or each of these groups believe should be discussed
      privately.  In addition, the Committee or at least its Chair
      should meet with the independent auditors and management quarterly to
      review the Trust's financials.  The Committee should also meet
      with management and independent auditors on an annual basis to review and
      discuss annual financial statements and the management's discussion and
      analysis of financial conditions and results of
  operations.
  ·
              Agendas,
      with input from management, shall be circulated to Committee members and
      relevant management personnel along with background information on a
      timely basis prior to the Committee
meetings.
  ·
              Minutes
      of each meeting shall be prepared by the Secretary to the
      Committee.
  ·
              The
      Chief Executive Officer and the Chief Financial Officer or their
      designates shall be available to attend at all meetings of the Committee
      upon the invitation of the
Committee.
  ·
              The
      Vice President, Accounting & Reporting and the Vice President,
      Treasury & Compliance and such other staff as appropriate to provide
      information to the Committee shall attend meetings upon invitation by the
      Committee.
  Reporting
/ Authority
  ·
              At
      the first Board meeting following a Committee meeting, the Committee will
      provide a verbal report to the Board of the material matters discussed and
      material resolutions passed at the Committee meeting.  The draft
      minutes of the Committee meeting will subsequently be provided to all
      Board members as soon as
practicable.
  ·
              Supporting
      schedules and information reviewed by the Committee shall be available for
      examination by any Director.
  ·
              The
      Committee shall have the authority to investigate any financial activity
      of the Trust and to communicate directly with the internal (if any) and
      independent auditors.  All employees are to cooperate as
      requested by the Committee.
  ·
              The
      Committee may retain, and set and pay the compensation for, persons having
      special expertise and/or obtain independent professional advice, including
      the engagement of independent counsel and other advisors, to assist in
      fulfilling its duties and responsibilities at the expense of Penn
      West.
  ·
              The
      Committee may delegate any of its duties and responsibilities hereunder to
      the Committee Chair or any group of members of the
    Committee.
  ·
              The
      Committee, in its capacity as a committee of the Board, shall determine
      appropriate funding and cause such funding to be available (i) to Penn
      West's independent auditors for the purpose of preparing and issuing an
      audit
   5
  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.
   6