U.S.
SECURITIES AND EXCHANGE COMMISSION


Washington,
D.C.  20549




FORM
40-F




(Check
One)




[   ]
Registration statement pursuant to Section 12 of the Securities Exchange Act of
1934


or


[X]
Annual report pursuant to section 13(a) or 15(d) of the Securities Exchange Act
of 1934




For the
fiscal year ended December 31, 2008




Commission
file number 1-15196






PROVIDENT
ENERGY TRUST


(Exact
name of registrant as specified in its charter)




Alberta,
      Canada
              (Province
      or other jurisdiction of
              incorporation
      or organization)
            1311
              (Primary
      Standard Industrial
              Classification
      Code Number (if applicable))
            Not
      applicable
              (I.R.S.
      Employer
              Identification
      Number (if
              Applicable))





Suite
2100, 250 – 2nd Street
S.W., Calgary, Alberta, Canada  T2P 0C1




(403)
296-2233




(Address
and Telephone Number of Registrant’s Principal Executive Offices)




Dorsey
& Whitney LLP


250
Park Avenue, New York, NY  10177-1500


(212)
415-9200




(Name,
Address (Including Zip Code) and Telephone Number




(Including
Area Code) of Agent For Service in the United States)




Securities
registered or to be registered pursuant to Section 12(b) of the
Act.




Title of each
      class
            
            Name of each exchange on which
      registeredTrust
      Units
            
            New
      York Stock Exchange




Securities
registered or to be registered pursuant to Section 12(g) of the
Act:  None




Securities
for which there is a reporting obligation pursuant to Section 15(d) of the
Act:  None




For
annual reports, indicate by check mark the information filed with this
Form:




[X]
      Annual Information Form
            [X]
      Audited Annual Financial Statements




Indicate
the number of outstanding shares of each of the issuer’s classes of capital or
common stock as of the close of the period covered by the annual
report.




Trust
Units outstanding at December 31, 2008:  259,087,789




Indicate
by check mark whether the registrant: (1) has filed all reports required to be
filed by Section 13 or 15(d) of the Exchange Act during the preceding 12 months
(or for such shorter period that the registrant was required to file such
reports); and (2) has been subject to such filing requirements for the past 90
days.




YesX                                No___





FORM
      40-F




Principal
      Documents




The
following documents have been filed as part of this Annual Report on Form 40-F,
beginning on the following page:




(a)
            Annual
      Information Form for the fiscal year ended December 31,
    2008;




(b)
            Management’s
      Discussion and Analysis of Financial Condition; and Results of Operations
      for the fiscal year ended December 31, 2008;
and




(c)
            Consolidated
      Financial Statements for the fiscal year ended December 31, 2008 (Note 18 to the Consolidated
      Financial Statements relates to United States Accounting Principles and
      Reporting (U.S. GAAP)).




40 F-1
  
  
  
  RENEWAL
ANNUAL INFORMATION FORM
  For the
year ended December 31, 2008
  
  
  
  
  
  
  March 19,
2009
  
 
 TABLE
OF CONTENTS
  GLOSSARY
      OF TERMS
                1
                
                PREMIUM
      DISTRIBUTION, DISTRIBUTION
                30REINVESTMENT
      AND OPTIONAL UNITABBREVIATIONS,
      TERMS AND
                4
                
                PURCHASE
      PLANCONVERSIONS
                
                
                DIRECTORS
      AND OFFICERS
                31PRESENTATION
      OF OIL AND GAS
                
                
                AUDIT
      COMMITTEE INFORMATION
                36RESERVES
      AND PRODUCTION
                
                
                INFORMATION
      CONCERNING THE OILINFORMATION
                4
                
                AND
      GAS INDUSTRY
                39NON-GAAP
      MEASURES
                5
                
                INFORMATION
      CONCERNING THE NATURAL GASMIDSTREAM,NGL
      PROCESSING ANDMARKETING
      INDUSTRY
                42NOTE
      REGARDING FORWARD-LOOKING
                5
                
                General
                42INFORMATION
                
                
                NGL
      Extraction
                43INCORPORATION
      AND STRUCTURE
                8
                
                NGL
      Fractionation
                43The
      Trust
                8
                
                NGL
      Transportation
                43Provident
      Energy Ltd.
                8
                
                NGL
      Storage
                43Provident
      Midstream Holdings LP
                8
                
                NGL
      Marketing
                43Provident
      Holdings Trust
                8
                
                Commercial
      Arrangements
                44Provident
      Acquisitions L.P.
                8
                
                RISK
      FACTORS
                45Provident
      Midstream L.P.
                8
                
                Oil
      and Gas Production Risk Factors
                45Provident
      Acquisitions Inc.
                9
                
                Natural
      Gas Midstream, NGL Processing and
                49Provident
      Energy Resources Inc.
                9
                
                Marketing
      Business Risk FactorsProvident
      Midstream Inc.
                9
                
                General
      Risk Factors
                52INTERCORPORATE
      RELATIONSHIPS
                10
                
                INTERESTS
      OF MANAGEMENT AND
                55INFORMATION
      CONCERNING THE TRUST,
                10
                
                OTHERS
      IN MATERIAL TRANSACTIONSPEL,
      PMHLP AND OTHER ENTITIES
                
                
                TRANSFER
      AGENT AND REGISTRAR
                55Provident
      Energy Trust
                10
                
                INTERESTS
      OF EXPERTS
                55Provident
      Energy Ltd.
                19
                
                MATERIAL
      CONTRACTS
                55Provident
      Midstream Holdings LP
                20
                
                DOCUMENTS
      INCORPORATED BY
                55Provident
      Acquisitions L.P.
                20
                
                REFERENCEProvident
      Energy Resources Inc.
                20
                
                PRINCIPAL
      HOLDERS OF TRUST UNITS
                56Provident
      Acquisitions Inc.
                20
                
                ADDITIONAL
      INFORMATION
                56Provident
      Midstream Inc.
                21Provident
      Midstream LP
                21
                
                SCHEDULE
      A - AUDIT COMMITTEE INFORMATIONPro
      Holding Company
                21GENERAL
      DEVELOPMENT OF THE
                21BUSINESS
      OF PROVIDENTRISK
      MANAGEMENT
                24OIL
      AND NATURAL GAS OPERATIONS
                25NATURAL
      GAS MIDSTREAM, NGL
                25PROCESSING
      AND MARKETINGOPERATIONSMARKET
      FOR SECURITIES
                27RECORD
      OF CASH DISTRIBUTIONS
                29
  - i
-
 GLOSSARY
OF TERMS
  "8 Percent Debentures" means
the 8 percent convertible unsecured subordinated debentures of the
Trust;
  "8.75 Percent Debentures" means
the 8.75 percent convertible unsecured subordinated debentures of the
Trust;
  "ABCA" means the Business Corporations Act
R.S.A. 2000, c. B-9, as amended, including the regulations promulgated
thereunder;
  "affiliate" or "associate" when used to
indicate a relationship with a person or company, means the same as set forth in
the Securities Act
(Alberta);
  "AJM" means AJM Petroleum
Consultants, independent petroleum engineers;
  "AMEX" means the American Stock
Exchange;
  "BEC L.P." means BreitBurn
Energy Company L.P., a Delaware limited partnership and previously an indirect
subsidiary of the Trust;
  "Board of Directors" or "Board" means the board of
directors of PEL;
  "BreitBurn" means BreitBurn
Energy Company LLC, a former California limited liability company;
  "BreitBurn Acquisition" means
the transaction in which the Trust acquired all of the issued and outstanding
shares of BreitBurn pursuant to an agreement and plan of merger dated
June 15, 2004 among the Trust, BreitBurn, Pro GP Corp., Pro LP Corp. and BB
Merger LLC;
  "BreitBurn MLP" means BreitBurn
Energy Partners L.P., a publicly traded Delaware limited
partnership;
  "Distributable Cash" means all
amounts distributed or to be distributed during any applicable period to
Unitholders;
  "Distribution Record Date"
means on or about the 20th day of
each calendar month or such other date as may be determined from time to time by
the Trustee;
  "Founders" means Founders
Energy Ltd., a predecessor of PEL;
  "Holdings Trust" means
Provident Holdings Trust;
  "Initial 6.5 Percent
Debentures" means the 6.5 percent convertible unsecured subordinated
debentures of the Trust issued on March 1, 2005;
  "Kinetic" means collectively,
Kinetic Resources U.S.A., a partnership formed under the laws of the State of
Michigan and Kinetic Resources (LPG), a partnership formed under the laws of the
Province of Alberta;
  "McDaniel" means McDaniel &
Associates Consultants Ltd., independent oil and gas reservoir engineers of
Calgary, Alberta;
  "Midstream Business" means the
midstream business of Provident and its subsidiaries including the Midstream NGL
Business and the business carried on with the Redwater Midstream NGL
Assets;
  
 - 1
-
 
 "Midstream NGL Acquisition"
means the acquisition by Provident of certain assets, shares and partnership
interests which comprised the natural gas liquids business of EnCana
Corporation, 1140102 Alberta Ltd., EnCana Midstream Inc., WD Energy Services
Inc. and EnCana Kerrobert Pipelines Limited for an aggregate purchase price of
$697 million, plus working capital and other adjustments which closed on
December 13, 2005;
  "Midstream NGL Business"means the natural gas
midstream, NGL processing and marketing business acquired by Provident from
EnCana Corporation, 1140102 Alberta Ltd., EnCana Midstream Inc., WD Energy
Services Inc. and EnCana Kerrobert Pipelines Limited;
  "Non-Resident" means a
non-resident of Canada for the purposes of the Tax Act;
  "NYSE" means the New York Stock
Exchange;
  "Option Plan" means the trust
unit option plan of the Trust providing for the issuance of options to acquire
Trust Units to employees, officers, directors and consultants of the
Trust;
  "PAI" means Provident
Acquisitions Inc.;
  "PEL"
means Provident Energy Ltd.;
  "PERI" means Provident Energy
Resources Inc.;
  "Permitted Investments" means:
(i) obligations issued or guaranteed by the government of Canada or any province
of Canada or any agency or instrumentality thereof; (ii) term deposits,
guaranteed investment certificates, certificates of deposit or bankers'
acceptances of or guaranteed by any Canadian chartered bank or other financial
institutions (including the Trustee and any affiliate of the Trustee) the
short-term debt or deposits of which have been rated at least A or the
equivalent by Standard & Poor's Corporation, Moody's Investors Service,
Inc., Canadian Bond Rating Service Inc. or Dominion Bond Rating Service Limited;
and (iii) commercial paper rated at least A or the equivalent by Canadian Bond
Rating Service Inc. or Dominion Bond Rating Service Limited, in each case
maturing within 180 days after the date of acquisition;
  "PHC" means Pro Holding
Company;
  "PMHLP" means Provident
Midstream Holdings LP;
  "PMLP" means Provident
Midstream LP;
  "PMI" means Provident Midstream
Inc.;
  "Provident"
means the Trust and where the context requires, includes PEL, PMHLP and the
other direct and indirect subsidiaries and affiliates of the
Trust;
 "Redwater
Acquisition" means the acquisition by Provident of the Redwater natural
gas liquids processing business from Williams Energy (Canada) Inc. for an
aggregate purchase price of approximately $298.6 million (including costs
associated with the acquisition), subject to certain adjustments, which closed
on September 30, 2003;
  "Redwater Midstream NGL Assets"
means the assets acquired pursuant to the Redwater Acquisition consisting of a
natural gas gathering system and processing plant, as well as an NGL extraction
plant, fractionation facilities, transportation systems and storage assets
previously owned by Williams Energy (Canada) Inc.;
  "Special Resolution" means a
resolution proposed to be passed as a special resolution at a meeting of
Unitholders (including an adjourned meeting) duly convened for the purpose and
held in accordance with the provisions of the Trust Indenture at which two or
more holders of at least 5 percent of the aggregate
  
 - 2
-
 
 number of
Trust Units then outstanding are present in person or by proxy and passed by the
affirmative votes of the holders of not less than 66 2/3 percent of the Trust
Units represented at the meeting and voted on a poll upon such
resolution;
  "Subsequent Investment" means
those investments which the Trust is permitted to make pursuant to the Trust
Indenture, namely royalties in respect of Provident's oil and gas properties and
securities of PEL or any other subsidiary of the Trust to fund the acquisition,
development, exploitation and disposition of all types of petroleum and natural
gas and energy related assets, including without limitation, facilities of any
kind, oil sands interests, electricity or power generating assets, and pipeline,
gathering, processing and transportation assets and whether effected through an
acquisition of assets or an acquisition of shares or other form of ownership
interest in any entity the substantial majority of the assets of which are
comprised of like assets;
  "subsidiary" means, when used
to indicate a relationship with another body corporate:
  (a)
              a
      body corporate which is controlled by (i) that other, or (ii) that other
      and one or more bodies corporate, each of which is controlled by that
      other, or (iii) two or more bodies corporate each of which is controlled
      by that other, or
 (b)
                a
      subsidiary of a body corporate that is the other's
  subsidiary;
 "Supplemental 6.5 Percent
Debentures" means the 6.5 percent convertible unsecured subordinated
debentures of the Trust issued on November 15, 2005;
  "Tax Act" means the Income Tax Act, R.S.C. 1985,
c.1, 5th Supplement and the regulations promulgated thereunder, each as
amended;
  "Trust" means Provident Energy
Trust, a trust settled pursuant to the laws of Alberta;
  "Trust Indenture" means the
trust indenture dated as of January 25, 2001 as amended from time to time,
between Computershare Trust Company of Canada and Founders;
  "Trust Fund", at any time,
shall mean such of the following monies, properties and assets that are at such
time held by the Trustee for the purposes of the Trust under the Trust
Indenture: (a) the initial $100 used to settle the Trust; (b) all funds realized
from the issuance of Trust Units; (c) any Permitted Investments in which funds
may from time to time be invested; (d) the initial royalty granted to the Trust;
(e) any Subsequent Investment; (f) any proceeds of disposition of any of the
foregoing property; (g) the common shares of Founders and the initial notes
of PEL held by the Trust; and (h) all income, interest, profit, gains and
accretions and additional assets, rights and benefits of any kind or nature
whatsoever arising directly or indirectly from or in connection with or accruing
to such foregoing property or such proceeds of disposition;
  "Trust Unit" means a unit of
the Trust, each unit representing an equal undivided beneficial interest
therein;
  "Trustee" means Computershare
Trust Company of Canada or such other trustee, from time to time, of the
Trust;
  "TSX" means the Toronto Stock
Exchange;
  "United States" and "U.S." mean the United States
of America, it territories and possessions, any state of the United States, and
the District of Columbia; and
  
 - 3
-
 
 "Unitholders" means the holders
from time to time of the Trust Units.
  Words
importing the singular number only include the plural and vice versa and words
importing any gender include all genders.  All dollar amounts set
forth in this Annual Information Form are in Canadian dollars, except where
otherwise indicated.
  ABBREVIATIONS,
TERMS AND CONVERSIONS
  In this
Renewal Annual Information Form, the abbreviations and terms set forth below
have the meanings indicated.
  Oil and Natural Gas
      Liquids
              Natural
    Gasbbls
              barrels
              mcf
              thousand
      cubic feetboed
      or boe/d
              barrels
      of oil equivalent per day
              bcf/d
              billion
      cubic feet per daybpd
      or bbl/d
              barrels
      of oil per day
              m3
              cubic
      metresmmbbls
              million
      barrels
              mmbtu
              million
      British Thermal UnitsNGLs
              natural
      gas liquids
              gj
              gigajouleSTB
              stock
      tank barrel of oilOtherboe
              means
      barrel of oil equivalent, using the conversion factor of 6 mcf of natural
      gas being equivalent to one bbl of oil, unless otherwise
      specified.  The conversion factor used to convert natural gas to
      oil equivalent is not necessarily based upon either energy or price
      equivalents at this time.WTI
              means
      West Texas Intermediate.API
              means
      the measure of the density or gravity of liquid petroleum products derived
      from a specific gravity.
  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
              0.0282cubic
      metres
              cubic
      feet
              35.494bbls
              cubic
      metres
              0.159cubic
      metres
              bbls
              6.289feet
              metres
              0.305metres
              feet
              3.281miles
              kilometres
              1.609kilometres
              miles
              0.621acres
              hectares
              0.405hectares
              acres
              2.471gigajoules
              mmbtu
              0.950bbls
              U.S.
      gallons
              0.42
 
  PRESENTATION
OF OIL AND GAS RESERVES AND PRODUCTION INFORMATION
  All oil
and natural gas reserve information contained or incorporated by reference in
this Renewal Annual Information Form has been prepared and presented in
accordance with National Instrument 51-101 Standard of Disclosure for Oil and
Gas Activities ("NI 51-101").  The actual oil and natural gas
reserves
  
 - 4
-
 
 and
future production will be greater than or less than the estimates provided in
this Annual Information Form.  The estimated future net revenue from
the production of the disclosed oil and natural gas reserves does not represent
the fair market value of these reserves.  Provident
hasadopted the standard of 6 mcf:1 boe when converting natural gas to
barrels of oil equivalent.  Boe may be misleading, particularly if
used in isolation.  A boe conversion ratio of 6 mcf:1 boe is based on
an energy equivalency conversion method primarily applicable at the burner tip
and does not represent a value equivalency at the wellhead.
  NON-GAAP
MEASURES
  In this
Renewal Annual Information Form, the Trust uses the terms "cash flow"
and "funds flow from operations" to refer to the cash available for
distribution to Unitholders and as indicators of financial
performance.  "Cash flow" and "funds flow from operations" are not
measures recognized by Canadian generally accepted accounting principles
("GAAP") and do not have standardized meanings prescribed by
GAAP.  Therefore, "cash flow" and "funds flow from operations" of the
Trust may not be comparable to similar measures presented by other issuers, and
investors are cautioned that "cash flow" and "funds flow from operations"
should not be construed as alternatives to net earnings, cash flow from
operating activities or other measures of financial performance calculated in
accordance with GAAP.  All references to "cash flow" and "funds
flow from operations" are based on cash provided by operating activities before
changes in non-cash working capital related to operating activities and site
restoration expenditures, as presented in the consolidated financial statements
of the Trust.  The
actual amount of cash that is distributed cannot be assured and future
distributions may vary.  Management also uses EBITDA to analyze
the operating performance of the Midstream business unit.  EBITDA as
presented does not have any standardized meaning prescribed by Canadian GAAP and
therefore it may not be comparable with the calculation of similar measures for
other entities. EBITDA as presented is not intended to represent operating cash
flow or operating profits for the period nor should it be viewed as an
alternative to cash flow from operating activities, net earnings or other
measures of financial performance calculated in accordance with Canadian
GAAP.  All references to EBITDA throughout this report are based on
earnings before interest, taxes, depletion, depreciation, accretion, and other
non-cash items ("EBITDA"). The Trust uses such terms as an indicator of
financial performance because such terms are commonly utilized by investors to
evaluate royalty trusts and income funds in the energy sector.  The
Trust believes that such terms are useful supplemental measures as they provide
investors with information of what cash is available for distribution from the
Trust to Unitholders in such periods.
  NOTE
REGARDING FORWARD-LOOKING INFORMATION
  This
Renewal Annual Information Form and the documents incorporated by reference
herein contain forward-looking information under applicable securities
legislation. This information relates to future events or the Trust's future
performance.  Such forward-looking information is provided for the
purpose of providing information about management's current expectations and
plans relating to the future.  Readers are cautioned that reliance on
such information may not be appropriate for other purposes, such as making
investment decisions.  All statements other than statements of
historical fact constitute forward-looking information.  In some
cases, forward-looking information can be identified by terminology such as
"may", "will", "should", "expect", "plan", "anticipate", "believe", "estimate",
"predict", "potential", "continue", or the negative of these terms or other
comparable terminology.  Statements relating to "reserves" or
"resources" are deemed to be forward-looking information, as they involve the
implied assessment, based on certain estimates and assumptions, that the
resources and reserves described can be profitably produced in the
future.  Forward looking information in this Renewal Annual
Information Form includes, but is not limited to, business strategy and
objectives, reserve quantities and the discounted present value of future net
cash flows from such reserves, net revenue, future production levels, capital
expenditures, exploration plans, development plans, acquisition and disposition
plans and the timing thereof, operating and other costs, royalty rates, budgeted
levels of cash distributions and the performance associated with Provident's
natural gas midstream, NGL processing and
  
 - 5
-
 
 marketing
business.  Forward-looking information is based on current
expectations, estimates and projections that involve a number of risks and
uncertainties which could cause actual events or results to differ materially
from those anticipated by the Trust and described in the forward-looking
information.  In addition, this Renewal Annual Information Form and
the documents incorporated by reference herein may contain forward-looking
information attributed to third party industry sources.  Undue
reliance should not be placed on forward-looking information, as there can be no
assurance that the plans, intentions or expectations upon which they are based
will occur.  By its nature, forward-looking information involves
numerous assumptions, known and unknown risks and uncertainties, both general
and specific, that contribute to the possibility that the predictions,
forecasts, projections and other forward-looking information will not
occur.  Forward-looking information in this Renewal Annual Information
Form and the documents incorporated by reference herein includes, but is not
limited to, information with respect to:
  ·
              Provident's
      ability to benefit from the combination of growth opportunities and the
      ability to grow through the capital
markets;
 ·
              Provident's acquisition
      strategy, the criteria to be considered in connection therewith and the
      benefits to be derived therefrom;
 ·
              sustainability
      and growth of production and reserves through prudent management and
      acquisitions;
 ·
              the
      emergence of accretive growth
opportunities;
 ·
              the
      ability to achieve an appropriate level of monthly cash
      distributions;
 ·
              the
      impact of Canadian governmental regulation
    on Provident;
 ·
              the
      existence, operation and strategy of the commodity price risk management
      program;
 ·
              the
      approximate and maximum amount of forward sales and hedging to be
      employed;
 ·
              changes
      in oil and natural gas prices and the impact of such changes on cash flow
      after financial derivative
instruments;
 ·
              the
      level of capital expenditures devoted to development activity rather than
      exploration;
 ·
              the
      sale, farming out or development using third party resources to exploit or
      produce certain exploration
properties;
 ·
              the
      use of development activity and acquisitions to replace and add to
      reserves;
 ·
              the
      quantity of oil and natural gas reserves and oil and natural gas
      production levels;
 ·
              currency,
      exchange and interest rates;
 ·
              the
      performance characteristics of Provident's natural gas midstream, NGL
      processing and marketing business;
 ·
              the
      growth opportunities associated with the natural gas midstream, NGL
      processing and marketing business;
and
 ·
              the
      nature of contractual arrangements with third parties in respect of
      Provident's natural gas midstream, NGL processing and marketing
      business.
  Although
the Trust believes that the expectations reflected in the forward-looking
information is  reasonable, there can be no assurance that such
expectations will prove to be correct.  The Trust can not guarantee
future results, levels of activity, performance, or
achievements.  Moreover, neither the Trust nor any other person
assumes responsibility for the accuracy and completeness of the forward-looking
information.  Some of the risks and other factors, some of which are
beyond the Trust's control, which could cause results to differ materially from
those expressed in the forward-looking information contained in this Renewal
Annual Information Form and the documents incorporated by reference herein
include, but are not limited to:
  ·
              general
      economic and credit conditions in Canada, the United States and
      globally;
 ·
              industry
      conditions associated with the NGL services, processing and marketing
      business;
 ·
              fluctuations
      in the price of crude oil, natural gas and natural gas
      liquids;
 
 - 6
-
 
 ·
              uncertainties
      associated with estimating
reserves;
 ·
              royalties
      payable in respect of oil and gas
production;
 ·
              interest
      payable on notes issued in connection with
  acquisitions;
 ·
              income
      tax legislation relating to income trusts, including the effect of new
      legislation taxing trust income;
 ·
              governmental
      regulation in North America of the oil and gas industry, including income
      tax and environmental regulation;
 ·
              fluctuation
      in foreign exchange or interest
rates;
 ·
              stock
      market volatility and market
valuations;
 ·
              the
      impact of environmental events;
 ·
              the
      need to obtain required approvals from regulatory
    authorities;
 ·
              unanticipated
      operating events which can reduce production or cause production to be
      shut-in or delayed;·
              failure
      to realize the anticipated benefits of acquisitions;·
              competition
      for, among other things, capital reserves, undeveloped lands and
      skilledpersonnel;
 ·
              failure
      to obtain industry partner and other third party consents and approvals,
      when required;
 ·
              risks
      associated with foreign ownership;
 ·
              third
      party performance of obligations under contractual arrangements;
      and
 ·
              the
      other factors set forth under "Risk Factors" in this Renewal Annual
      Information Form.
  Readers
are cautioned that the foregoing list is not exhaustive of all possible risks
and uncertainties.  With respect to forward-looking information
contained in this Renewal Annual Information Form, the Trust has made
assumptions regarding, among other things:
  ·
              future
      natural gas and crude oil prices;
 ·
              the
      ability of Provident to obtain qualified staff and equipment in a timely
      and cost-efficient manner to meet
demand;
 ·
              the
      regulatory framework regarding royalties, taxes and environmental matters
      in which Provident conducts its
business;
 ·
              the
      impact of increasing competition;
and
 ·
              Provident's ability
      to obtain financing on acceptable
terms.
 ·
              the
      general stability of the economic and political environment in
      which Provident operates;
 ·
              the
      timely receipt of any required regulatory
  approvals;
 ·
              the
      ability of the operator of the projects which Provident has an interest in
      to operate the field in a safe, efficient and effective
      manner;
 ·
              field
      production rates and decline rates;
 ·
              the
      ability to replace and expand oil and natural gas reserves through
      acquisition, development or
exploration;
 ·
              the
      timing and costs of pipeline, storage and facility construction and
      expansion and the ability of Provident to secure adequate product
      transportation;
 ·
              currency,
      exchange and interest rates; and
 ·
              the
      ability of Provident to successfully market its crude oil, natural
      gas and NGLs.
  Readers
are cautioned that the foregoing list is not exhaustive of all factors and
assumptions which have been used.  The forward-looking information
contained or incorporated by reference in this Renewal Annual Information Form
is made as of the date hereof and the Trust undertakes no obligation to update
publicly or revise any forward-looking information, whether as a result of new
information, future events
  
 - 7
-
 
 or
otherwise unless required by applicable securities laws. The forward-looking
information contained or incorporated by reference in this Renewal Annual
Information Form is expressly qualified by this cautionary
statement.
  INCORPORATION
AND STRUCTURE
  The
Trust
  Provident
Energy Trust is an open-end unincorporated investment trust governed by the laws
of the Province of Alberta and created pursuant to the Trust
Indenture.  The head and principal offices of the Trust are located at
2100, 250 - 2nd Street
S.W., Calgary, Alberta T2P 0C1.  The registered office of the Trust is
located at 3700, 400 - 3rd Avenue S.W., Calgary, Alberta T2P 4H2.
  Provident
Energy Ltd.
  Provident
Energy Ltd. is a corporation the common shares of which are wholly-owned by the
Trust. PEL was incorporated under the ABCA on January 19, 2001 and was
amalgamated with Founders pursuant to a plan of arrangement involving the Trust,
PEL and Founders effective March 6, 2001.  PEL subsequently
amalgamated with Maxx Petroleum Ltd. ("Maxx") effective May 25, 2001 pursuant to
a plan of arrangement involving the Trust, PEL and Maxx.  PELwas also
amalgamated with Richland Petroleum Corporation ("Richland") effective January
16, 2002 pursuant to a plan of arrangement involving the Trust, PEL and
Richland.  PEL was amalgamated with PEL Management Corporation
pursuant to a management internalization transaction involving the Trust,
PEL PEL Management Corporation and its shareholders effective January 17,
2003.  PEL was also amalgamated with Olympia Energy Inc. and Viracocha
Energy Inc. on June 1, 2004 pursuant to plans of arrangement involving the
Trust, PEL Viracocha Energy Inc. and Olympia Energy Inc.  The head and
principal offices of PEL are located at 2100, 250 - 2nd Street
S.W., Calgary, Alberta T2P 0C1.  The registered office of PEL is
located at 3700, 400 - 3rd Avenue S.W., Calgary,
Alberta T2P 4H2.
  Provident
Midstream Holdings LP
 PMHLP is
a limited partnership registered in the Province of Alberta.  PMHLP
was formed pursuant to a limited partnership agreement dated September 30,
2008.  PMHLP directly and indirectly holds substantially all of the
equity interests in the subsidiaries of the Trust which hold the Midstream
Business including PMLP and PMI.
  The
general partner of PMHLP is Provident Midstream Holdings GP ULC which holds a
0.1% interest in the limited partnership.  The Trust is the limited
partner of PMHLP with a 99.9% interest in the limited
partnership.  The head and principal office of PMHLP are located at
2100, 250 - 2nd
Street S.W., Calgary, Alberta T2P 0C1.  The registered office of PMHLP
is located at 3700, 400 - 3rd
Avenue S.W., Calgary, Alberta T2P 4H2.
 Provident
Holdings Trust
  Provident
Holdings Trust is an open-end unincorporated commercial trust governed by the
laws of the Province of Alberta.  Holdings Trust was formed pursuant
to a trust indenture dated April 25, 2002 and is wholly-owned by the
Trust.  Holdings Trust currently holds a 99 percent limited
partnership interest in Provident Acquisitions L.P.  The head and
principal offices of Holdings Trust are located at 2100, 250 - 2nd Street
S.W., Calgary, Alberta T2P 0C1.  The registered office of Holdings
Trust is located at 3700, 400 – 3rd Avenue S.W., Calgary, Alberta T2P
4H2.
  Provident
Acquisitions L.P.
  Provident
Acquisitions L.P. is a limited partnership registered in the Province of
Alberta.  Provident Acquisitions L.P. was formed pursuant to a limited
partnership agreement dated April 19, 2002.  The general partner of
Provident Acquisitions L.P. is Provident which holds a 1 percent interest in the
partnership.  Holdings Trust is the limited partner of Provident
Acquisitions L.P. with a 99 percent interest in the partnership.  The
head and principal offices of Provident Acquisitions L.P. are located at 2100,
250 - 2nd Street
S.W., Calgary, Alberta T2P 0C1.  The registered office of Provident
Acquisitions L.P. is located at 3700, 400 - 3rd Avenue S.W., Calgary,
Alberta T2P 4H2.
  Provident
Midstream L.P.
  Provident
Midstream L.P. is a limited partnership registered in the Province of
Alberta.  Provident Midstream L.P. was formed pursuant to a limited
partnership agreement dated December 8, 2005.
  
 - 8
-
  Provident
Midstream L.P. directly and indirectly holds the Canadian partnership interests
acquired pursuant to the Midstream NGL Acquisition.  The general
partner of Provident Midstream L.P. is Provident GP Inc. which holds a 0.1
percent interest in the partnership.  PMHLP and PMI are the limited
partners of Provident Midstream L.P. with a 99.9 percent total interest in the
partnership.  Provident Midstream L.P. also holds a 98.5 percent
partnership interest in Empress NGL Partnership, a general partnership formed
under the laws of Alberta, which in turn holds a 99 percent partnership interest
in Kinetic Resources LPG, a general partnership formed under the laws of
Alberta.  The head and principal offices of Provident Midstream L.P.
are located at 2100, 250 - 2nd Street
S.W., Calgary, Alberta T2P 0C1.  The registered office of Provident
Midstream L.P. is located at 3700, 400 - 3rd Avenue S.W., Calgary, Alberta T2P
4H2.
  Provident
Acquisitions Inc.
  Provident
Acquisitions Inc. is a corporation wholly-owned by PEL.  PAI was
incorporated under the ABCA on August 19, 2002.  The head and
principal offices of PAI are located at 2100, 250 - 2nd Street
S.W., Calgary, Alberta T2P 0C1.  The registered office of PAI is
located at 3700, 400 - 3rd Avenue S.W., Calgary, Alberta T2P 4H2.
  Provident
Energy Resources Inc.
  Provident
Energy Resources Inc. is a corporation wholly-owned by PEL.  PERI was
incorporated under the ABCA on May 9, 2007.  PERI amalgamated with
Capitol Energy Resources Ltd. on June 21, 2007 and amalgamated with Triwest
Energy Inc. on December 4, 2007.  The head and principal offices of
PERI are located at 2100, 250 - 2nd Street
S.W., Calgary, Alberta T2P 0C1.  The registered office of PERI is
located at 3700, 400 - 3rd Avenue
S.W., Calgary, Alberta T2P 4H2.
  Provident
Midstream Inc.
  Provident
Midstream Inc. is a corporation wholly-owned by Pro Holding
Company.  PMI was incorporated under the ABCA on June 6,
2005.  PMI holds an interest in Provident Midstream
L.P.  The head and principal offices of PMI are located at 2100, 250 -
2nd
Street S.W., Calgary, Alberta T2P 0C1.  The registered office of PMI
is located at 3700, 400 - 3rd Avenue S.W., Calgary, Alberta  T2P
4H3.
  - 9
-
  INTERCORPORATE
RELATIONSHIPS
  The
following diagram of the Trust and its material subsidiaries describes the
flow of cash from the oil and gas properties and the natural gas midstream, NGL
processing and marketing business to the Trust.
  
 
   INFORMATION
CONCERNING THE TRUST, PEL, PMHLP AND OTHER ENTITIES
  Provident
Energy Trust
  Cash
Flow
  The Trust
indirectly holds interests in petroleum and natural gas properties and the
natural gas midstream, NGL processing and marketing business through PEL,
PMHLP and various other subsidiaries.  Cash flow from the
petroleum and natural gas properties flows from PEL and certain other
subsidiaries to the Trust by way of royalty payments and interest payments and
principal repayments on notes issued to the Trust from time to time. Cash
flow from the Midstream Business flows from PMHLP and its subsidiariesto the Trust by way of interest payments and principal repayments on
notes issued to PMHLP and by way of partnership distributions from the
subsidiaries of PMHLP to PMHLP and from PMHLP to the
Trust.  Distributable income generated by the royalty payments,
interest payments, the principal repayments and partnership distributions is
then distributed monthly to the Unitholders.
  Under the
terms of the Trust Indenture the Trust is also entitled to (i) invest in
securities of PEL from time to time; (ii) acquire royalties; (iii)
temporarily hold cash and Permitted Investments for the purposes of paying the
expenses and liabilities of the Trust and paying amounts payable by the Trust in
connection with the redemption of any Trust Units and making distributions to
Unitholders; (iv) acquire or invest in Subsequent Investments; and (v) pay the
costs, fees and expenses associated with or incidental to the
foregoing.
  Cash
Distributions
  The
Trustee intends to make cash distributions on or about the 15th day of each
month to Unitholders of record on the immediately preceding Distribution Record
Date in cash amounts comprised of the interest, royalty and dividend income
of the Trust, net of the Trust's administrative expenses.  In
addition, Unitholders may, at the discretion of the Trustee, receive
distributions in respect of repayments of principal to the Trust on notes issued
by the Trust from time to time.
  The Trust
seeks to provide cash distributions, subject to, among other things,
fluctuations in the quantity of petroleum and natural gas substances produced,
prices received for that production, hedging contract
  
 - 10
-
 
 receipts
and payments, taxes, direct expenses of the Trust, reclamation fund
contributions, fluctuations in the demand for NGLs and natural gas, competition
from other industry
participants, operational matters and hazards related to the natural gas
midstream, NGL processing and marketing business, capital expenditures, debt
servicing, operating costs, debt service charges and general and administrative
expenses as determined necessary by PEL on behalf of the Trust.
  Trust
Units
  An
unlimited number of Trust Units may be created and issued pursuant to the Trust
Indenture.  Each Trust Unit represents an equal fractional undivided
beneficial interest in any distribution from the Trust (whether of net income,
net realized capital gains or other amounts) and in any net assets of the Trust
in the event of termination or winding-up of the Trust.  All Trust
Units outstanding from time to time shall be entitled to an equal share of any
distributions from, and in any net assets of, the Trust in the event of the
termination or winding-up of the Trust.  All Trust Units rank among
themselves equally and rateably without discrimination, preference or
priority.  Each Trust Unit is transferable, is not subject to any
conversion or pre-emptive rights and entitles the holder thereof to require the
Trust to redeem any or all of the Trust Units held by such holder and to one
vote at all meetings of holders of Trust Units for each Trust Unit
held.  Holders of Trust Units shall not be subject to any liability in
contract or tort or of any other kind in connection with the assets, obligations
or affairs of the Trust or with respect to any acts performed by the Trustee or
any other person pursuant to the Trust Indenture.
  8
Percent Debentures
  In July
2004, the Trust issued 50.0 million aggregate principal amount of convertible
unsecured subordinated debentures.  The 8 Percent Debentures mature on
July 31, 2009 and bear interest at a rate of 8 percent per annum, payable
semi-annually in arrears on July 31 and January 31 in each year.  The
8 Percent Debentures are convertible at the option of the holder into Trust
Units at any time prior to the earlier of July 31, 2009 and the business day
immediately preceding any date specified by the Trust for redemption at a
conversion price of $12.00 per Trust Unit, subject to adjustment in certain
circumstances.  After July 31, 2007 and prior to maturity, the Trust
may redeem the 8 Percent Debentures in whole or in part from time to time at a
price of $1,050 per 8 Percent Debenture from July 31, 2007 until July 31, 2008
and at a price of $1,025 per 8 Percent Debenture thereafter until maturity, in
each case plus accrued and unpaid interest.  On redemption or maturity
of the 8 Percent Debentures, the Trust may, subject to regulatory approval,
elect to satisfy the redemption price or principal amount by issuing Trust Units
to the 8 Percent Debenture holder.  As of March 19, 2009, there
was $25.1 million aggregate principal amount of 8 Percent Debentures
outstanding.
  Initial
6.5 Percent Debentures
  In March
2005, the Trust issued $100.0 million aggregate principal amount of convertible
unsecured subordinated debentures.  The Initial 6.5 Percent Debentures
mature on August 31, 2012 and bear interest at a rate of 6.5 percent per
annum, payable semi-annually in arrears on August 31 and February 28
in each year.  The Initial 6.5 Percent Debentures are convertible at
the option of the holder into Trust Units at any time prior to the earlier of
August 31, 2012 and the business day immediately preceding any date
specified by the Trust for redemption at a conversion price of $13.75 per Trust
Unit, subject to adjustment in certain circumstances.  After
August 31, 2008 and prior to maturity, the Trust may redeem the Initial 6.5
Percent Debentures in whole or in part from time to time at a price of $1,050
per Initial 6.5 Percent Debenture from August 31, 2008 until
August 31, 2009, at a price of $1,025 per Initial 6.5 Percent Debenture
after August 31, 2009 and on or before August 31, 2010 and after
August 31, 2010 and prior to maturity at a price of $1,000 per Initial 6.5
Percent Debenture, in each case plus accrued and unpaid interest.  On
redemption or maturity of the Initial 6.5 Percent Debentures, the Trust may,
subject to regulatory approval, elect to satisfy the redemption price or
principal amount by issuing Trust Units to the Initial 6.5 Percent Debenture
holder.  As of March 19, 2009, there was $99.0 million aggregate
principal amount of Initial 6.5 Percent Debentures outstanding.
  
 - 11
-
 
 Supplemental
6.5 Percent Debentures
  In
November 2005, the Trust issued $150.0 million aggregate principal amount of
convertible unsecured subordinated debentures.  The Supplemental 6.5
Percent Debentures mature on April 30, 2011 and bear interest at a rate of
6.5 percent per annum, payable semi-annually in arrears on April 30 and
October 31 in each year, commencing April 30, 2006.  The
Supplemental 6.5 Percent Debentures are convertible at the option of the holder
into Trust Units at any time prior to the earlier of April 30, 2011 and the
business day immediately preceding any date specified by the Trust for
redemption at a conversion price of $14.75 per Trust Unit, subject to adjustment
in certain circumstances.  After October 31, 2008 and prior to
maturity, the Trust may redeem the Supplemental 6.5 Percent Debentures in whole
or in part from time to time at a price of $1,050 per 6.5 Percent Debenture from
October 31, 2008 until October 31, 2009, at a price of $1,025 per Supplemental
6.5 Percent Debenture after October 31, 2009 and on or before October 31,
2011, in each case plus accrued and unpaid interest.  On redemption or
maturity of the Supplemental 6.5 Percent Debentures, the Trust may, subject to
regulatory approval, elect to satisfy the redemption price or principal amount
by issuing Trust Units to the Supplemental 6.5 Percent Debenture
holder.  As of March 19, 2008, there was $150.0 million aggregate
principal amount of Supplemental 6.5 Percent Debentures
outstanding.
  Debt
Financing
  The Trust
has entered into a credit agreement (the "Canadian Credit Facility") dated as of
May 4, 2007, as amended, among the Trust, National Bank of Canada, as
administrative agent, and a syndicate of Canadian chartered banks and other
Canadian and foreign financial institutions (the "Lenders").  Pursuant
to the Canadian Credit Facility, the Lenders have agreed to provide the Trust
with a revolving credit facility in the principal amount of $1.105 billion (or
the equivalent in U.S. dollars) and an operating credit facility in the
principal amount of $20 million (or the equivalent in U.S. dollars) for the
general corporate purposes of the Trust.
  The
Canadian Credit Facility bears interest in accordance with a pricing grid based
on the Trust's debt to EBITDA multiple calculated using a rolling twelve month
EBITDA.  Based on the Trust's EBITDA for the year ended December 31,
2008, the interest rate pursuant to the pricing grid in Canadian bankers
acceptance plus 0.875 percent.  The Canadian Credit Facility is
secured by a first fixed and floating charge debenture, a general assignment of
book debts, a negative pledge and an undertaking to provide, if determined
necessary by the Lenders, first charges over major petroleum and natural gas
reserves of Provident.
  The Trust
may draw on the facility by way of Canadian prime rate loans, U.S. base rate
loans, banker’s acceptances, letters of credit or LIBOR loans.  At
December 31, 2008, $504.7 million (excluding outstanding letters of credit to
trade accounts) was drawn on the Canadian Credit Facility.
  The
Canadian Credit Facility has a revolving three year term expiring on May 30,
2011 (the "Maturity Date").  The Trust can extend the revolving
period by an additional year, no earlier than 90 days and no later than 30 days
prior to the end of the first year of the applicable three year revolving
period.  If the Lenders do not extend the revolving period, or the
Trust chooses not to extend, the credit facility will be terminated and the
loan balance will become due and payable in full on the Maturity Date. In 2008,
under the terms of the credit facility, the Maturity Date was extended from May
30, 2010 to May 30, 2011.
  In
accordance with the Canadian Credit Facility, the Trust must maintain certain
financial covenants so long as any indebtedness is outstanding under the
facility and will not assume or create any mortgage, charge or encumbrance on
the assets of the Trust or certain subsidiaries other than permitted
encumbrances.  In addition, the facility contains other standard
covenants restricting the Trust's ability to incur indebtedness, dispose of
assets, enter into hedging arrangements or amend, supplement, cancel or
terminate any material term of the Trust Indenture (except for any changes that
are not adverse to the Lenders).  The Canadian Credit Facility also
prohibits distributions to the Unitholders: (i) if they are out
 
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-
 
  of the
ordinary course of business; (ii) during the period commencing after a borrowing
base shortfall has occurred (as defined in the facility) and ending when such
shortfall has been eliminated; (iii) during the period commencing after a
default has occurred and ending when such default has been cured; (iv) after an
event of default has occurred; (v) after the maturity date; (vi) if they would
cause a default or event of default or would impair the ability of the Trust or
its subsidiaries to fulfill its obligations under the Canadian Credit Facility
or the security provided in respect thereof; and (vii) the aggregate amount of
such distributions and payments during the preceding four fiscal quarters
exceeds cumulative available cash flow (as defined in the
facility).
  The
events of default under the Canadian Credit Facility include a default in
payment of any principal or interest when due, failure to comply with any
covenants or conditions, failure to observe or comply with any financial
covenant, a change of control of the Trust or certain subsidiaries and other
standard events which are typical of credit facilities. The Trust has also
agreed to indemnify the Lenders in certain circumstances.
  A copy of
the Canadian Credit Facility has been filed on SEDAR and is available under the
Trust's issuer profile on SEDAR at www.sedar.com.
  Meetings
of Unitholders
  Meetings
of holders of Trust Units will be called and held annually for, among other
things, the election of the directors of PEL and the appointment of the auditors
of the Trust.  The Trust Indenture provides that meetings of
Unitholders must be called and held for, among other matters, the election or
removal of the Trustee, the appointment or removal of the auditors of the Trust,
the approval of certain amendments to the Trust Indenture, to assign, transfer
or dispose of royalties as an entirety or substantially as an entirety, and the
commencement of winding-up the affairs of the Trust.
  Unitholders
may attend and vote at all meetings of Unitholders either in person or by proxy
and a proxy holder need not be a holder of Trust Units.  Two persons
present in person or represented by proxy and representing in the aggregate at
least 5 percent of the votes attaching to all outstanding Trust Units shall
constitute a quorum for the transaction of business at all such
meetings.  For the purposes of determining such quorum, the holders of
any issued special voting units who are present at the meeting shall be regarded
as representing outstanding Trust Units equivalent in number to the votes
attaching to such special voting units.
  Termination
of the Trust
  Unitholders
may vote to terminate the Trust at any meeting of Unitholders duly called for
that purpose, 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.
  Unless
the Trust is terminated or extended by vote of Unitholders earlier, 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 sell
and convert into money certain royalties and other assets in one transaction or
in a series of transactions at public or private sale and do all other acts as
may be appropriate to liquidate assets and shall in all respects act in
accordance with the directions, if any, of the Unitholders in respect of the
Special Resolution authorizing the termination of the Trust.  After
paying, retiring or discharging or making provision for the payment, retirement
or discharge of all known liabilities and obligations of the Trust and providing
for indemnity against any other outstanding liabilities and obligations, the
Trustee shall distribute the remaining part of the proceeds of the sale of the
assets together with any cash remaining in the Trust among the Unitholders in
accordance with their pro rata share.
  
 - 13
-
 
 Trust
Unit Option Plan
  The Trust
discontinued its trust unit option plan as of May 2, 2005.  No options
were issued under the Option Plan after March 2005 and the Trust does not intend
to issue any further options under the Option Plan in the
future.  However, options to acquire Trust Units previously granted
under the Option Plan will continue to remain exercisable in accordance with
their terms.  Additional information concerning the Option Plan is
included in the Trust's most recently filed proxy statement and information
circular.  As of March 19, 2009, there were 0.9 million options
granted and outstanding under the Option Plan.
  Premium
Distribution, Distribution Reinvestment and Optional Unit Purchase
Plan
  The Trust
has implemented a premium distribution, distribution reinvestment and optional
unit purchase plan (the "DRIP") to provide holders of Trust Units with a means
to automatically reinvest sums received on account of distributions on Trust
Units. Provident reserves the right to prorate the participation in the DRIP to
manage the amount of cash reinvested in the Trust and the Trust Units issued
under the DRIP. Computershare Trust Company of Canada, as plan agent, may at the
election of a participant (a) purchase Trust Units with the cash
distributions at 95 percent of the market value of the Trust Units, or
(b) elect to purchase additional Trust Units with the cash distributions
and deliver such Trust Units to a broker in exchange for a premium cash
distribution equal to an amount up to 102 percent of the monthly cash
distribution, or (c) purchase new Trust Units under the optional unit purchase
plan at a subscription price of 100 percent of the average market price of the
Trust Units.  If a participant has elected either (a) or (b), the plan
agent may, on behalf of such participant, purchase additional Trust Units with
the cash distributions at the market value of such Trust Units. Residents of
Canada are eligible to elect options (a), (b), or (c). Due to regulatory
restrictions, residents of the United States are eligible to elect option (a)
only at this time.  See "Premium Distribution, Distribution
Reinvestment and Optional Unit Purchase Plan" in this Renewal Annual Information
Form.
  Taxation
of the Trust
  The Trust
is a unit trust and a mutual fund trust for purposes of the Tax
Act.  The legislation implementing the proposals announced by the
Department of Finance (Canada) ("Finance") on October 31, 2006 respecting the
taxation of certain "specified investment flow-through" ("SIFT") trusts and SIFT
partnerships and their unitholders (the "SIFT Rules") received Royal Assent and
became law on June 22, 2007.  The SIFT Rules impose a tax at the
entity level on distributions of certain income from SIFT trusts (which would
include the Trust) and partnerships at a rate of tax comparable to the combined
federal and provincial corporate tax and to treat such distributions as
dividends to the Unitholders.  Existing SIFT trusts will have a
four-year transition period, and subject to the qualifications below, will not
be subject to the SIFT Rules until January 1, 2011.  The application
of the SIFT Rules to the Trust is expected to result in adverse tax consequences
to the Trust and indirectly, to certain Unitholders, including most particularly
Unitholders that are tax deferred trusts (such as registered retirement savings
plans, registered retirement income funds, deferred profit sharing plans and
registered education savings plans) and non-residents of Canada, and may impact
cash distributions from the Trust.
  On July
14, 2008, Finance announced proposed amendments to the Tax Act including
technical amendments to clarify certain aspects of the SIFT Rules and to provide
rules to facilitate the conversion of existing SIFT trusts 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 income trust into a taxable Canadian corporation and the
winding-up of the trust’s underlying structure. The first alternative involves
the winding-up of the trust into a taxable Canadian corporation whereas the
second approach involves the distribution by the publicly-traded income trust of
shares of an underlying taxable Canadian corporation to its
unitholders.  Bill C-10, which received Royal Assent on March 12,
2009, contained legislation implementing the Conversion
Rules.
  
 - 14
-
  Pursuant
to the SIFT Rules, commencing January 1, 2011 (provided the Trust only
experiences "normal growth" and no "undue expansion" before then) certain
distributions from the Trust which would have otherwise been taxed as ordinary
income generally will be characterized as dividends in addition to being subject
to tax at corporate rates at the Trust level.  Returns of capital
generally are (and under the SIFT Rules will continue to be) tax-deferred for
Unitholders who are resident in Canada for purposes of the Tax Act (and reduce
such Unitholder's adjusted cost base in the Trust Unit for purposes of the Tax
Act).  Distributions, whether of income or capital, to a Unitholder
who is not resident in Canada for purposes of the Tax Act, or that is a
partnership that is not a "Canadian partnership" for purposes of the Tax Act,
generally will be subject to Canadian withholding tax.
  Management
believes that the SIFT Rules have already impaired and may continue to impair
the value of the Trust Units, which would be expected to increase the cost to
the Trust of raising capital in the public capital markets.  In
addition, management believes that the SIFT Rules have and will continue to: (a)
reduce the competitive advantage that the Trust and other Canadian trusts enjoy
relative to their corporate peers in raising capital in a tax-efficient manner,
and (b) place the Trust and other Canadian trusts at a competitive disadvantage
relative to similar industry competitors such as U.S. master limited
partnerships.  The SIFT Rules have and will continue to make the Trust
Units less attractive as an acquisition currency.  As a result, it has
become more difficult for the Trust to compete effectively for acquisition
opportunities.  There can be no assurance that the Trust will be able
to reorganize its legal and tax structure to substantially mitigate the expected
impact of the SIFT Rules.
  The
adverse tax consequences associated with the SIFT Rules could be realized by the
Trust sooner than January 1, 2011 if the Trust experiences growth other than
"normal growth" before then.  On December 15, 2006 Finance issued
guidelines with respect to what would be considered "normal growth" for this
purpose (the "Guidelines").  The Guidelines provide that "normal
growth" would include equity growth within certain "safe harbour" limits,
measured by reference to a SIFT trust's market capitalization as of the end of
trading on October 31, 2006 (which would include 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 the greater of $50 million and
40 percent of a SIFT trust's October 31, 2006 market capitalization for the
period from November 1, 2006 to December 31, 2007, and the greater of $50
million and 20 percent of a SIFT trust's October 31, 2006 market capitalization
for each of calendar 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 normal growth
constraints include the following:
  (a)
              new
      equity for these purposes includes units and debt that is convertible into
      units (and may include other substitutes for equity if attempts are made
      to develop such substitutes);
  (b)
              replacing
      debt that was outstanding as of October 31, 2006 with new equity, whether
      by a conversion into trust units of convertible debentures or otherwise,
      will not be considered growth for these purposes and will therefore not
      affect the safe harbour limits;
  (c)
              the
      exchange for trust units, of exchangeable partnership units or
      exchangeable shares that were outstanding on October 31, 2006 will not be
      considered growth for those purposes and will therefore not affect the
      safe harbour where the issuance of the trust units is made in satisfaction
      of the exercise of the exchange right by a person other than the SIFT;
      and
  (d)
              the
      ability to acquire other trusts without impacting normal growth
      rules.
  On
December 4, 2008, Finance announced changes to the Guidelines to allow a SIFT
trust to accelerate the utilization of the SIFT trust's annual permitted
expansion amount for each of 2009 and 2010 so that the amount is available on
and after December 4, 2008. This change does not alter the maximum
  - 15
-
  permitted expansion
threshold for a SIFT trust, but it allows a SIFT trust 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
Trust's market capitalization as of the close of trading on October 31, 2006,
having regard only to its issued and outstanding publicly-traded Trust Units,
was approximately $2,776 million, which means the Trust's "safe harbour" equity
growth amount for the period ending December 31, 2008 is approximately $1,666
million and for each of the calendar years of 2009 and 2010 is an additional
approximately $555 million (in any case, not including equity issued to replace
debt that was outstanding on October 31, 2006) and the permitted expansion room
for each of 2009 and 2010 is available to be used by the Trust after December 4,
2008.
  While
these Guidelines are such that it is unlikely they would affect the Trust's
ability to raise the capital required to maintain and grow its existing
operations in the ordinary course during the transition period, they could
adversely affect the cost of raising capital and the Trust's ability to
undertake more significant acquisitions.  See "Risk Factors - General
Risk Factors".
  Limitation
on Non-Resident Trust Unitholders
  Generally,
a trust cannot qualify as a "mutual fund trust" for the purposes of the Tax Act
if it is established or is being maintained primarily for the benefit of
non-residents. Although not without uncertainty, this is generally accepted to
exist in most situations where Non-Resident holders own significantly in excess
of 50 percent of the aggregate number of Trust Units issued and outstanding.
However, there is currently an exception to the non-resident ownership
restriction in paragraph 132(7)(a) of the Tax Act where not more than 10 percent
of the trust's property has at any time consisted of "taxable Canadian
property".
  In
accordance with the Trust Indenture, in order to ensure the maintenance of the
Trust's "mutual fund trust" status, Provident will: (i) prior to the
consummation of any transaction involving the acquisition by the Trust of any
Subsequent Investment; (ii) prior to any material modification to the Trust
Fund other than as contemplated by subclause (i); (iii) promptly following
any proposed amendment to paragraph 132(7)(a) of the Tax Act (which
provision relates to the level of "taxable Canadian property") or the
publication of any administrative bulletin or other notice of interpretation
relating to the interpretation or application of such section; or
(iv) otherwise at any time when requested by the Trustee, obtain an opinion
of counsel confirming whether the Trust is, at the date thereof and following
such transaction or event (which in the case of (iii) shall mean the coming into
effect of the amendment or change of interpretation), entitled to rely on
paragraph 132(7)(a) of the Tax Act (or any successor provision thereto) for
purposes of qualifying as a "mutual fund trust" under the Tax Act.
  If at any
time the board of directors of PEL determines, in its sole discretion, or
becomes aware that the Trust's ability to continue to rely on
paragraph 132(7)(a) of the Tax Act (or any successor provision thereto) for
purposes of qualifying as a "mutual fund trust" thereunder is in jeopardy, then
forthwith after such determination PEL will take such steps as are
necessary or desirable to ensure that the Trust is not maintained primarily for
the benefit of Non-Residents.
  PEL may,
at any time and from time to time, in its sole discretion, request that the
Trustee make reasonable efforts, as practicable in the circumstances, to obtain
declarations as to beneficial ownership, perform residency searches of
shareholder and beneficial shareholder mailing address lists and take such other
steps specified by PEL, at the cost of the Trust, to determine or estimate as
best possible the residence of the beneficial owners of Trust
Units.  If at any
time the board of directors of PEL, in its sole discretion, determines that it
is in the best interest of the Trust, Provident, notwithstanding the ability of
the Trust to continue to rely on subsection
  
 - 16
-
 
 132(7)(a)
of the Tax Act for the purpose of qualifying as a "mutual fund trust" under the
Tax Act, may (i) require the Trustee to refuse to accept a subscription for
Trust Units from, or issue or register a transfer of Trust Units to, a person
unless the person provides a declaration to Provident that the Trust Units to be
issued or transferred to such person will not when issued or transferred be
beneficially owned by a Non-Resident; (ii) to the extent practicable in the
circumstances, send a notice to registered holders of Trust Units which are
beneficially owned by Non-Residents, chosen in inverse order to the order of
acquisition or registration of such Trust Units beneficially owned by
Non-Residents or in such other manner as PEL may consider equitable and
practicable, requiring them to sell their Trust Units which are beneficially
owned by Non-Residents or a specified portion thereof within a specified period
of not less than 60 days.
  If the
Unitholders receiving such notice have not sold the specified number of such
Trust Units or provided PEL with satisfactory evidence that such Trust Units are
not beneficially owned by Non-Residents within such period, PEL may, on behalf
of such registered Unitholder, sell such Trust Units and, in the interim,
suspend the voting and distribution rights attached to such Trust Units and make
any distribution in respect of such Trust Units by depositing such amount in a
separate bank account in a Canadian chartered bank (net of any applicable
taxes).
  Any sale
shall be made on any stock exchange on which the Trust Units are then listed
and, upon such sale, the affected holders shall cease to be holders of Trust
Units so disposed of and their rights shall be limited to receiving the net
proceeds of sale, and any distribution in respect thereof deposited as
aforesaid, net of applicable taxes and costs of sale, upon surrender of the
certificates representing such Trust Units; (iii) delist the Trust Units
from any non-Canadian stock exchange; and (iv) take such other actions as
the board of directors of PEL determines, in its sole discretion, are
appropriate in the circumstances that will reduce or limit the number of Trust
Units held by Non-Residents to ensure that the Trust is not maintained primarily
for the benefit of Non-Residents.
  Redemption
Right
  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 requesting
redemption.  Upon receipt of the redemption request by the Trust, the
holder thereof shall only be entitled to receive a price per Trust Unit (the
"Market Redemption Price") equal to the lesser of: (i) 90 percent of the simple
average of the closing 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 surrendered
for redemption; and (ii) 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 surrendered for redemption.
  The
aggregate Market Redemption Price payable by the Trust in respect of any Trust
Units surrendered for redemption during any calendar month shall be satisfied by
way of a cash payment on the last day of the following month.  In
certain circumstances, the aggregate Market Redemption Price payable by the
Trust may be satisfied by distributing notes having an aggregate principal
amount equal to the aggregate Market Redemption Price of the Trust Units
tendered for redemption.
  It is
anticipated that this redemption right will not be the primary mechanism for
holders of Trust Units to dispose of their Trust Units. Notes which may be
distributed in specie to holders of Trust Units in connection with a redemption
will not be listed on any stock exchange and no market is expected todevelop
in such notes. Notes will not be qualified investments for trusts governed by
registered retirement savings plans, registered retirement income funds,
registered education savings plans, deferred profit sharing plans, registered
disability savings plans or tax-free savings accounts.
  - 17
-
  Trustee
  Computershare
Trust Company of Canada is the trustee of the Trust.  The Trustee is
responsible for, among other things:  (a) accepting subscriptions for
Trust Units and issuing Trust Units pursuant thereto; (b) maintaining the books
and records of the Trust and providing timely reports to Unitholders; and (c)
paying cash distributions to Unitholders.  The Trust Indenture
provides that the Trustee shall exercise its powers and carry out its functions
thereunder as Trustee honestly, in good faith and in the best interests of the
Trust and 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.
  The
initial term of the Trustee's appointment was until the first annual meeting of
Unitholders.  Thereafter, the Trustee shall be reappointed or changed
every year as may be determined by a majority of the votes cast at a meeting of
the Unitholders.  The Trustee may resign upon 60 days' notice to the
Trust.  The Trustee may also be removed by Special
Resolution.  Such resignation or removal becomes effective upon the
acceptance or appointment of a successor trustee.
  The
Trustee, its directors, officers, employees, shareholders and agents shall not
be liable to any Unitholder or any other person, in tort, contract or otherwise,
in connection with any matter pertaining to the Trust or the Trust Fund, arising
from the exercise by the Trustee of any powers, authorities or discretion
conferred under the Trust Indenture, unless such liabilities arise out of the
gross negligence, wilful default or fraud of the Trustee or any of its
directors, officers, employees, shareholders or agents. In the exercise of the
powers, authorities or discretion conferred upon the Trustee under the Trust
Indenture, the Trustee is and shall be conclusively deemed to be acting as
Trustee of the assets of the Trust and shall not be subject to any personal
liability for any debts, liabilities, obligations, claims, demands, judgements,
costs, charges or expenses against or with respect to the Trust or the Trust
Fund.  In addition, the Trust Indenture contains other customary
provisions limiting the liability of the Trustee.
  Amendments
to the Trust Indenture
  The Trust
Indenture may be amended or altered from time to time by Special
Resolution.  The Trustee may, without the approval of the Unitholders,
make certain amendments to the Trust Indenture, including amendments for the
purpose of:
  ·
              ensuring
      the Trust's continuing compliance with applicable laws or requirements of
      any governmental agency or authority of Canada or of any
      province;
  ·
              ensuring
      that the Trust will satisfy the provisions of each of subsections 108(2)
      and 132(6) of the Tax Act as from time to time amended or
      replaced;
  ·
              ensuring
      that such additional protection is provided for interests of Unitholders
      as the Trustee may consider
expedient;
  ·
              removing
      or curing any conflicts or inconsistencies between the provisions of the
      Trust Indenture or any supplemental indenture and any other agreement of
      the Trust or any offering document pursuant to which securities of the
      Trust are issued, or any applicable law or regulations of any
      jurisdiction, provided that in the opinion of the Trustee the rights of
      the Trustee and of the Unitholders are not prejudiced thereby;
      and
 
 ·
              curing,
      correcting or rectifying any ambiguities, defective or inconsistent
      provisions, errors, mistakes or omissions, provided that in the opinion of
      the Trustee the rights of the Trustee and of the Unitholders are not
      prejudiced thereby.
  - 18
-
 Provident
Energy Ltd.
  The
principal business of PEL is to manage and administer the operating activities
associated with the oil and gas properties and the natural gas midstream, NGL
processing and marketing business. PEL is also engaged in the acquisition,
exploitation, development and production of crude oil and natural gas in the
Western Canadian Sedimentary Basin.  PEL currently has 603
employees, consultants and contract operators at its head office location and in
several field offices within the core areas of Lloydminster, Northwest Alberta,
West central Alberta, Southern Alberta, Southwest Saskatchewan, Southeast
Saskatchewan, and the NGL midstream facilities in Redwater and Empress, Alberta,
Sarnia, Ontario, Lynchburg, Virginia and Houston, Texas.
  Delegation
of Authority, Administration and Trust Governance
  The board
of directors of PEL has generally been delegated the significant management
decisions of the Trust.  In particular, the Trustee has delegated to
PEL responsibility for any and all matters relating to:  (a) the
redemption of Trust Units; (b) the acquisition of Subsequent Investments by
the Trust and the negotiation of management agreements respecting Subsequent
Investments; (c) any offering of securities of the Trust
including:  (i) the listing and maintaining of the listing on the
TSX or NYSE of the Trust Units; (ii) the filing of documents or obtaining
of permission from any governmental or regulatory authority or the taking of any
other step under federal or provincial law to enable securities which a holder
of Trust Units is entitled to receive to be properly and legally delivered and
thereafter traded; (iii) ensuring compliance with all applicable laws;
(iv) all matters relating to the content of any prospectus, information
memorandum, private placement memorandum and similar public or private offering
documents, and the certification thereof; (v) all matters concerning the
terms of the sale or issuance of Trust Units or rights to Trust Units; (d) the
determination of any Distribution Record Date other than the last date of each
calendar month; and (e) the determination of any borrowing under the Trust
Indenture.  Holders of Trust Units are entitled to elect all of the
members of the board of directors of PEL pursuant to the terms of the Unanimous
Shareholder Agreement.
  Decision
Making
  The board
of directors of PEL supervises the management of the business and affairs of the
Trust, including the business and affairs of the Trust delegated to
PEL.  In particular, significant operational decisions and all
decisions relating to: (i) the acquisition and disposition of properties
for a purchase price or proceeds in excessof certain defined
thresholds; (ii) the approval of annual operating and capital expenditure
budgets; and (iii) establishment of credit facilities, are made by the
board of directors of PEL.  In addition, the Trustee has delegated
certain matters to the board of directors of PEL including all decisions
relating to: (i) the issuance of additional Trust Units; and (ii) the
determination of the amount of Distributable Cash.  Any amendment to
royalties will require the approval of the board of directors of PEL on behalf
of the Trust.  The board of directors of PEL generally holds regularly
scheduled meetings to review the business and affairs of PEL and make any
necessary decisions relating thereto.
  Common
Shares
  All of
the issued and outstanding common shares of PEL are held by the Trust. Each
common share of PEL entitles its holder to receive notice of and to attend all
meetings of the shareholders of PEL and to one vote at such
meetings.  The holders of the common shares are, at the discretion of
the board of directors of PEL and subject to applicable legal restrictions,
entitled to receive any dividends declared by the board of directors on the
common shares.  All such common shares are entitled
  
 - 19
-
 
 to share
equally in any distribution of the assets of PEL upon the liquidation,
dissolution, bankruptcy or winding-up of PELor other distribution of its assets
among its shareholders for the purpose of winding-up its
affairs.  Such participation is subject to the rights, privileges,
restrictions and conditions attaching to any instruments having priority over
the common shares.
  No
dividends have been paid on the common shares of PEL.  Any decision to
pay dividends on the common shares of PEL in the future will be made by the
board of directors of PEL on the basis of PEL's earnings, financial requirements
and other conditions existing at the time.
  Royalties
  PEL has
granted certain royalties to the Trust which entitle the Trust to cash
distributions in respect of the production from oil and gas properties held by
PEL.
  PEL is
entitled to make farmouts or other similar dispositions of specific interests in
any part of the properties subject to the royalties, and upon the farmee or
other participant earning its interest pursuant to the farmout or other
disposition, these royalties shall burden only the working interest retained by
or reserved to PEL.
  PEL is
required to establish a reserve to fund future well bore and facility
abandonment and environmental and reclamation obligations and liabilities (the
"Reclamation Fund").  PEL currently funds this reserve at $0.30 per
barrel of oil equivalent (converting gas to oil at 6:1) (in 2007 - $0.30; in
2006 - $0.30; in 2005 - $0.30;  in 2004 and 2003 - $0.25 per barrel of
oil equivalent and in 2002 and prior - $0.20 per barrel of oil equivalent
converting gas to oil at 10:1) produced, less current year well bore and
facility abandonment and environmental and reclamation obligations and
liabilities out of production revenues and other revenues for a calendar year
into the Reclamation Fund.
  Notes
  From time
to time, PEL has issued notes to the Trust in connection with certain
acquisitions and other transactions undertaken by the Trust.  Cash
flow from PEL's producing properties distributed from PEL to the Trust includes
interest payments and principal repayments on the various notes held by the
Trust.
  Provident
Midstream Holdings LP
  PMHLP is a holding
partnership which directly and indirectly (through PHC) holds all of the equity
interests in PMLP and PMI, other than the interests held by PEL through the
preferred shares PEL holds in PHC. PMHLP was
formed in September 2008 and holds, directly and indirectly,
substantially all of the equity interests in the subsidiaries of the Trust
which hold the Midstream Business.
  Provident
Acquisitions L.P.
  Provident
Acquisitions L.P. holds certain southeast Alberta properties and heavy oil
wells.  Holdings Trust holds a 99 percent interest in Provident
Acquisitions L.P.  Holdings Trust is wholly-owned by the
Trust.  The general partner of Provident Acquisitions L.P. is PEL and
both Holdings Trust and Provident Acquisition LP are managed by
PEL.  Provident Acquisitions L.P. has granted a royalty to the Trust
entitling the Trust to receive the cash flow from all present and future oil and
gas properties and related tangibles owned by Provident Acquisitions L.P. after
certain cost expenditures and deductions.
  Provident
Energy Resources Inc.
  PERI is a
direct wholly owned subsidiary of the Trust.  PERI is managed by
PEL.  PERI holds the oil and gas assets acquired on the acquisition of
Capitol Energy Resources Ltd. and Triwest Energy Inc.  PERI has
granted a royalty to the Trust to receive the cash flow from all present and
future oil and gas properties and related tangibles owned by PERI.
  Provident
Acquisitions Inc.
  PAI is a
direct wholly owned subsidiary of PEL. PAI holds certain Alberta and
Saskatchewan properties that were acquired through the purchase of Meota
Resources Corp. PAI is managed by PEL and has 67 percent interest in 10101150
Saskatchewan Ltd. and a 0.00001 percent interest in Meota
(2000) Partnership. 10101150 Saskatchewan Ltd. holds a 59.9999 percent interest
in the Meota (2000) Partnership. PEL holds a 40 percent interest in the Meota
(2000) Partnership. PAI has granted a royalty to the Trust entitling the Trust
to receive the cash flow from all present and future oil and gas properties and
related tangibles owned by PAI after certain cost expenditures and
deductions.
  - 20
-
  Provident
Midstream Inc.
  PMI holds
an interest in Provident Midstream L.P.  The Trust receives cash flow
generated by PMI by way of interest and principal payments on debt owing from
PMI to PMHLP which is then distributed to the Trust by way of distributions on
limited partnership units.
  Provident
Midstream LP
  PMI and
PMHLP are the limited partners of PMLP.  The general partner of PMLP
is Provident GP Inc. which is a wholly owned subsidiary of PMHLP.
  PMLP
holds, either directly or indirectly through partnerships, all of the assets
located in Canadaacquired as a result of
the Midstream NGL Acquisition and the Redwater Acquisition, other than minor
general partnership interests held by Provident GP Inc., a wholly-owned
subsidiary of PMHLP.  Cash flow from these assets flows to PMHLP and
then on to the Trust by way of distributions on limited partnership
units.
  Pro
Holding Company
  PHC is
owned by PMHLP (common shares) and PEL (preferred shares).  PHC owns
all of the shares of Pro US LLC and Pro Midstream Company which in turn hold all
of the partnership interests in the Kinetic Resources U.S.A.
partnership.  Pro US LLC holds all of the assets located in the
U.S.acquired as a
result of the Midstream NGL Acquisition, other than those held by the Kinetic
Resources U.S.A. partnership.  PHC also owns the common shares of
PMI.
  GENERAL
DEVELOPMENT OF THE BUSINESS OF PROVIDENT
  The
following information describes the development of the business of 
Provident and its material subsidiaries over the last three completed financial
years.
  On
January 17, 2006, the Trust announced the appointment of Mr. David I. Holm to
the newly-created position of Executive Vice President, Finance and Strategy,
effective February 1, 2006. Mr. Holm is responsible for overseeing corporate
functions at Provident, including finance, strategy, planning, business
development, risk management, and communications.  On March 28, 2006,
Mr. Holm was appointed Corporate Secretary.
  On May
12, 2006, the Trust announced that BreitBurn MLP filed a Form S-1
registration statement with the U.S. Securities and Exchange Commission in order
to pursue an initial public offering.
  BreitBurn MLP's
assets consisted primarily of producing and non-producing crude oil reserves
located in the Los Angeles Basin in California and the Wind River and Big Horn
Basins in Wyoming, which were transferred into BreitBurn MLP from
BEC L.P.  The Los Angeles based management team continued to operate both
BreitBurn MLP and BEC L.P.
  Effective June 30, 2006,
Randall J. Findlay, the President of PEL, retired from his management
responsibilities with Provident.  Mr. Findlay remains on the board of
directors of PEL.  Thomas W. Buchanan, the Chief Executive Officer of
PEL, was also appointed President of PEL following Mr. Findlay's
resignation.
 
 - 21
-
  On July
11, 2006, Provident entered into a purchase and sale agreement (the "Purchase
and Sale Agreement"), as well as certain related agreements, with a privately
owned U.S. based oil and gas company and certain of its affiliates, which
provided for the acquisition of certain oil and natural gas properties (the
"Rainbow Assets"), through a series of steps which included the acquisition of
certain partnership interests and the subsequent distribution of the Rainbow
Assets to Provident out of such partnerships, for a purchase price of
approximately $473.0 million.  The acquisition closed on August 31,
2006.
  The
Rainbow Assets consist of oil, natural gas and natural gas liquids assets
located in northwestern Alberta with production weighted approximately 90
percent natural gas and 10 percent light oil and NGLs, which as at June 1, 2006
were producing approximately 33 million cubic feet of gas equivalent per day
(5,500 barrels of oil equivalent per day), before deduction of royalties owed to
others (comprised of approximately 30.5 million cubic feet per day of natural
gas and 420 barrels per day of oil and NGLs).
  Included
in the Rainbow Assets were approximately 126,100 gross (81,139 net) acres of
undeveloped land at an average 64 percent working interest as well as
proprietary and licensed seismic (approximately 4,901 kilometres of 2D seismic
data and 673 square kilometres of 3D seismic data) to assist Provident in
ongoing identification and evaluation of upside potential associated with the
Rainbow Assets.
  The
acquisition of the Rainbow Assets was partially funded by the Trust's public
offering of 16,325,000 subscription receipts at a price of $13.85 per
subscription receipt for proceeds of $226.1 million, which closed on July 31,
2006.  Upon the closing of the acquisition, holders of subscription
receipts received one Trust Unit for each subscription receipt held and, as a
reduction to the purchase price in respect of such subscription receipts, $0.12
per subscription receipt held.
  On
October 4, 2006, BreitBurn MLP priced its initial public offering of
6,900,000 common units at U.S. $18.50 per limited partnership unit and the units
began trading October 4, 2006 on the NASDAQ Global Select Market under the
ticket symbol "BBEP."  After this transaction, the Trust owned
approximately 66 percent of BreitBurn MLP.  The Trust used the
net proceeds of U.S. $115.2 million from the initial public offering of
BreitBurn MLP to pay down debt in Canada and the U.S.
  In May
2007, BreitBurn MLP completed two oil and gas property acquisitions, one in
Florida for cash consideration of U.S. $108.1 million and one in California for
cash consideration of U.S. $92.5 million.  The acquisitions were
financed by the issue of units by BreitBurn MLP to institutional investors,
decreasing the Trust's ownership in BreitBurn to approximately 50
percent.
  On May 3,
2007, the Trust entered into an acquisition agreement with Capitol Energy
Resources Ltd.  ("Capitol") pursuant to which the Trust agreed to make
an offer to purchase all of the issued and outstanding common shares of Capitol
(the "Capitol Shares"), including Capitol Shares that became outstanding upon
exercise of options to purchase Capitol Shares.
  In
conjunction with the acquisition of Capitol, the Trust entered into a bought
deal agreement with a syndicate of underwriters to issue 29,313,727 subscription
receipts at a price of $12.75 per subscription receipt for gross proceeds of
approximately $373.75 million.   Each subscription receipt holder
automatically received one Trust Unit on June 20, 2007, the date the Trust
acquired the Capitol Shares.
  On June
20, 2007, the Trust announced that PERI had acquired approximately 96.2% of the
outstanding Capitol Shares for $8.16 in cash per share. Following the expiry of
the offer, PERI acquired the remaining Capitol Shares pursuant to the compulsory
acquisition provisions of the ABCA.  The Capitol Shares were de-listed
from the TSX on June 21, 2007.  Effective June 21, 2007, PERI and
Capitol were amalgamated with the amalgamated company continuing under the name
"Provident Energy Resources Inc.".
  
 - 22
-
  The total
cash amount paid by the Trust to purchase all of the outstanding Capitol Shares
was approximately $466 million.  The Trust also assumed Capitol's net
debt of approximately $41 million.  The Trust satisfied the funding
requirements for the Capitol Shares from existing credit facilities and from the
proceeds of the offering of subscription receipts of the Trust.
  On
September 12, 2007, the Trust announced the acquisition of gas-weighted
producing assets by BreitBurn MLP.  BreitBurn MLP signed a definitive
agreement to acquire all of the natural gas, oil and midstream assets in
Michigan, Indiana and Kentucky of Quicksilver Resources Inc. ("Quicksilver") for
US$750 million in cash and 21.348 million BreitBurn MLP common
units.  BreitBurn MLP acquired the Quicksilver gas-weighted producing
assets located primarily in the Michigan Antrim Shale.
  BreitBurn
MLP financed the Quicksilver acquisition with a combination of a private
placement of new equity, bank debt, and a vendor take-back by Quicksilver of
21.348 million common units of BreitBurn MLP.  The Trust did not
participate in the equity offering.  The BreitBurn MLP transaction
reduced the Trust's ownership in BreitBurn MLP from approximately 50 percent to
approximately 22 percent.  The Trust continued to control BreitBurn
MLP through its 96 percent ownership of BreitBurn GP LLC, the general
partner.
  On
October 22, 2007, the Trust entered into an acquisition agreement with Triwest
Energy Inc. ("Triwest") pursuant to which the Trust agreed to make an offer to
purchase all of the issued and outstanding class "A" voting common shares of
Triwest (the "Triwest Shares"), including Triwest Shares that became outstanding
upon exercise of options to purchase Triwest Shares, for 0.6539 Trust Units and
$0.1569 in cash for each Triwest Share.  Triwest was an independent
company engaged in the acquisition, exploration, development and production of
oil and natural gas in western Canada, with operations principally conducted in
Saskatchewan.
  On
December 4, 2007, the Trust announced that PERI had acquired 9,533,279 of the
outstanding Triwest Shares, representing approximately 99.7% of the outstanding
Triwest Shares (calculated on a diluted basis), pursuant to the
offer.  PERI acquired the remaining Triwest Shares not deposited
pursuant to the offer in accordance with the compulsory acquisition procedures
of the ABCA following the expiry time.  An aggregate of 6,251,149
Trust Units were issued and approximately $1.5 million in cash paid in payment
of all of the outstanding Triwest Shares.
  PERI and
Triwest were subsequently amalgamated on December 4, 2007 with the resulting
amalgamated company continuing as "Provident Energy Resources Inc."
  On
February 5, 2008, the Trust outlined the strategic initiatives it was
undertaking respecting its investment in its U.S. businesses, BreitBurn MLP and
BEC L.P.   The Trust also provided an update with respect to its
planning process initiated to facilitate business growth and performance and
access to capital.  The planning process was also in response to the
Canadian Federal Government's decision to impose growth restrictions on Canadian
energy trusts and, effective 2011, to implement a tax on income trust
distributions.
  On June
17, 2008, the Trust sold a portion of its U.S. oil and gas production business,
consisting of its 22 percent interest in BreitBurn MLP and its 96 percent
interest in BreitBurn GP LLC, for cash proceeds, net of transaction costs, of
U.S. $342.2 million.  The Trust has recorded a gain on sale of $187.9
million and $127.7 million in current tax expense, related to this
transaction.  Proceeds from the sale were initially applied to
Provident's Canadian senior credit facility.
  On
August 26, 2008, the Trust closed the sale of the remaining portion of its U.S.
oil and gas production business, comprised of an approximate 96 percent interest
in BEC L.P., for total consideration of U.S. $300.4 million, consisting of cash
proceeds, net of transaction costs, of U.S. $290.4 million and a U.S. $10
million note.  The Trust has recorded a gain on sale of $75.7 million
and $66.9 million in current tax
  - 23
-
 
 expense
related to this transaction.  Proceeds from the sale were initially
applied to Provident's Canadian senior credit facility.
  On
October 1, 2008, the Trust implemented certain internal reorganization
transactions intended to better segregate the structure of the Trust's
subsidiaries along business lines.  As a result of these transactions,
the entities which carry on the Midstream Business are now largely held by
PMHLP.
  The
strategic review process announced
on February 5, 2008was undertaken with the intent to optimize business
performance, facilitate growth, improve the cost of capital, and ensure the
Trust is being accorded the appropriate value for its component
businesses.  Although Provident made some strides towards these goals
commencing with the sale of its U.S. oil and gas exploration and production
business, the impact of the current economic downturn has created additional
challenges.  Despite this increase in complexity, Provident continues
to assess structural options while focusing on business fundamentals and
capitalizing on high-return growth
opportunities.
  RISK
MANAGEMENT
  Provident's
commodity price risk management program utilizes derivative instruments to
provide insurance against lower commodity prices and margins.  The
program provides support for cash distributions, capital programs and bank
financing.  The risk management strategy protects a percentage of
Provident's oil and natural gas production against a decline in commodity prices
while, with some products, allowing Provident to participate in a rising
commodity price environment.  It provides price stabilization and
protection of a percentage of inventory values and fractionation spread margin
associated with the Midstream Business.  As well, the risk management
strategy reduces foreign exchange risk due to the exposure arising from the
conversion of U.S. dollars into Canadian dollars.
  Management
believes that financial markets currently provide adequate liquidity through
price discovery and active credit-worthy counterparties
for Provident to continue to execute the program in
2009.  The derivative instruments Provident uses include puts, calls,
costless collars, participating swaps, and fixed price products that settle
against indexed referenced pricing.
  Provident's credit policy
governs the activities undertaken to mitigate non-performance risk by
counterparties to financial derivative instruments.  Activities
undertaken include regular monitoring of counterparty exposure to approved
credit limits, financial reviews of all active counterparties, utilizing International Swap Dealers
Association (ISDA) agreements and obtaining financial assurances where
warranted.  In addition, Provident has a diversified base of available
counterparties.
  Details of the financial
instruments in place at December 31, 2008 are summarized in Note 13 to the
Trust's audited consolidated financial statements for the year ended
 
 - 24
-
 
 December
31, 2008 and are incorporated by reference herein.  The Trust's
audited consolidated financial statements for the year ended December 31, 2008
have been filed on SEDAR and are available under the Trust's issuer profile at
www.sedar.com.
  Provident also
purchases property insurance, business interruption insurance,
liability/pollution insurance and well control insurance to manage the risks
associated with the operation of  Provident's assets. Provident also
purchases directors and officers insurance.
  OIL
AND NATURAL GAS OPERATIONS
  Information
concerning Provident's oil and gas reserves and other information relating
thereto is contained in the Statement of Reserves Data and other Oil and Gas
Information on Form 51-101F1 which has been filed on SEDAR at
www.sedar.com.
 Provident's
reserves were evaluated by McDaniel and AJM effective December 31, 2008, in
accordance with NI 51-101.  McDaniel and AJM are independent qualified
reserves evaluators appointed pursuant to NI 51-101.  The McDaniel
evaluation report is dated March 2, 2009 with a preparation date of December 31,
2008.  The AJM evaluation report is dated March 2, 2009 with a
preparation date of December 31, 2008.
  The
Trust's Statement of Reserves Data and Other Oil and Gas Information on Form
51-101F1, the Report on Reserves Data by Independent Qualified Reserves
Evaluator or Auditor on Form 51-101F2 from each of McDaniel and AJM both dated
March 2, 2009 and the Report of Management and Directors on Oil and Gas
Disclosure on Form 51-101F3 dated March 11, 2009 have been filed on SEDAR
at www.sedar.com and are incorporated by reference in this Renewal Annual
Information Form.
  NATURAL
GAS MIDSTREAM, NGL PROCESSING AND MARKETING OPERATIONS
  The
Midstream Business
  The
Midstream Business unit extracts, processes, stores, transports and markets NGLs
for Provident and offers these services to third party customers.  The
Midstream Business contains three business lines.
  The
Empress East business line is comprised of the following core
assets:
  ·
              Approximately
      2.0 Bcfd of extraction capacity at Empress Alberta.  This is the
      combination of 67.5 percent ownership of the 1.2 Bcfd capacity Provident
      Empress NGL Extraction plant, 12.4 percent ownership in the 1.1 Bcfd
      capacity ATCO Plant, 8.3 percent ownership in the 2.4 Bcfd capacity
      Spectra Plant and 33.0 percent ownership in the 2.7 Bcfd capacity BP
      Empress 1 Plant.
  ·
              100
      percent ownership of a 50,000 bpd debutanizer at Empress Alberta which
      removes condensate from the NGL mix for sale as a diluent to blend with
      heavy oil.
  ·
              50
      percent ownership in the 130,000 bpd Kerrobert Pipeline which transports
      NGL from Empress to Kerrobert, Saskatchewan, and 50 percent ownership in a
      2.5 mmbbl underground storage facility near Kerrobert which facilitates
      injection of NGLs into the Enbridge Pipeline System.  Along the
      Enbridge Pipeline System, Provident holds 18.3 percent ownership of a
      300,000 barrel Superior Storage staging facility required for transfer of
      NGL between Enbridge lines at Superior, and 18.3 percent ownership of the
      10,000 bpd Superior Depropanizer which extracts up to 6,600 bpd of propane
      for sale in the local market.
  ·
              In
      Sarnia, Ontario, 10.3 percent ownership of an approximately 150,000 bpd
      fractionator, 1.7 mmbbl of raw product storage capacity and 18 percent of
      5.0 mmbbl of finished product storage and
      rail, truck and pipeline terminalling.  An additional 0.5 mmbbls
      of specification product storage is also available in the Sarnia
      area.
  ·
              A
      propane distribution terminal at Lynchburg,
  Virginia.
  - 25
-
 ·
              A
      rail car fleet of approximately 300 rail cars under long term lease
      agreement.
  The
Empress East business line extracts NGLs from natural gas at the Empress
straddle plants and sells finished products into markets in Central Canada and
the Eastern United States.  The margin in this business is determined
primarily by the "frac spread ratio", which is the ratio between crude oil
prices and natural gas prices.  The higher the ratio, the better this
business line will perform.  There is also a differential between
propane, butane and condensate (collectively, these products are referred to as
"propane-plus") prices and crude oil prices which can change prices received and
margins realized for Midstream products separate from frac spread ratio
changes.  Operating margins reflect the prices realized on sale of
these products less the weighted average cost of purchasing, fractionating,
storing and transporting the products.  The business is seasonal and
carries inventory that generally builds over the second and third quarters of
the year and is sold in the fourth quarter and the first quarter of the
following year.
  The
Redwater West business line is comprised of the following core
assets:
  ·
              100
      percent ownership of the Redwater NGL Fractionation Facility,
      incorporating a 65,000 bpd fractionation, storage and transportation
      facility that includes 12 pipeline receipt and delivery points, railcar
      loading facilities with direct access to CN rail and indirect access to CP
      rail, finished product truck loading facilities, six million gross barrels
      of salt cavern storage, and a 55,000 bpd condensate rail offloading
      facility with a 260 railcar marshalling and storage yard.  The
      facility can process high-sulphur NGL streams and is one of only two
      ethane-plus fractionation facilities in western Canada capable of
      extracting ethane from the natural gas liquids
  stream.
  ·
              Approximately
      7,000 bpd of leased fractionation and storage capacity at other
      facilities.
  ·
              43.3
      percent direct ownership and 100 percent control of all products from the
      750 mmcfd Younger NGL extraction plant located at Taylor in northeastern
      British Columbia.  The Younger Plant supplies local markets as
      well as Provident's Redwater plant near
  Edmonton.
  ·
              100
      percent ownership of the 565 kilometer proprietary Liquids Gathering
      System ("LGS") that runs along the Alberta-British Columbia border
      providing access to a highly active basin for liquids-rich natural gas
      exploration and exploitation.  The LGS connects to Pembina
      Pipeline at La Glace Alberta. Provident has long-term shipping rights on
      Pembina Pipeline, extending the NGL supply transportation network through
      to the Redwater fractionation
facility.
  ·
              A
      rail car fleet of approximately 700 rail cars under long term lease
      agreement.
  The
Redwater West business line purchases an NGL mix from various producers and
fractionates it into finished products at the Redwater fractionation facility
near Edmonton, Alberta.  Because the feedstock for this business line
is primarily NGL mix rather than natural gas, the frac spread ratio has a
smaller impact on margin than in the Empress East business line.  This
facility also has the largest rail rack in Western Canada to receive products
for delivery into the local condensate market.  Provident has
considerably increased its participation in the condensate market over the past
year, reflecting the increased demand for condensate as diluent for heavy oil
production.
  The
Commercial Services business line includes services such as fractionation,
storage and loading at Provident's Redwater facility on a fee
basis.  It also includes pipeline tariff income from Provident's
ownership of the Liquids Gathering System in Northwest Alberta which flows into
Pembina's pipeline from LaGlace to Redwater.  Provident also collects
tariff income from its 50 percent ownership in the Kerrobert Pipeline which
transports NGLs from Empress to Kerrobert for injection into the Enbridge
pipeline for delivery to Sarnia.  Provident owns a debutanizer at its
Empress facility, which removes
 
 - 26
-
 
 condensate
from the NGL mix for sale as a diluent to blend with heavy oil.  This
service is provided to a major energy company on a long term cost of service
basis.  Earnings from this business line of the Midstream segment have
little direct exposure to market prices volatility and are thus relatively
stable.
  Long
term contracts
  At the
Redwater fractionation facility, a significant portion of the available propane
plus fractionation capacity is contracted through a long term fee for service
arrangement with third parties.
  In 2006
and 2007, Provident commissioned a 60,000 bpd condensate rail off-loading
terminal at Redwater, a significant portion of which is under long term
contracts with two major energy producers.
  The
ethane produced from Provident's facilities at Empress and Redwater is largely
sold under long term contracts.
  Provident
has a long term contract on a cost of service basis for the majority of its
50,000 bbl/d Empress debutanizer facility.  Provident also has a long
term contract for 500,000 barrels of specification product storage in the Sarnia
area.
  MARKET
FOR SECURITIES
  The
outstanding Trust Units of the Trust are listed and posted for trading on the
TSX under the symbol PVE.UN and the NYSE under the symbol PVX.  The
Trust Units were previously listed on the AMEX prior to December 16, 2005, at
which time the Trust Units began trading on the NYSE.  The 8 Percent
Debentures, Initial 6.5 Percent Debentures and Supplemental 6.5 Percent
Debentures of the Trust are listed and posted for trading on the TSX under the
symbol PVE.DB.B, PVE.DB.C and PVE.DB.D, respectively.
  The
following table summarizes the Trust Unit and debenture trading activity for the
periods indicated on both the Toronto Stock Exchange and the New York Stock
Exchange, as applicable.
  Toronto
Stock Exchange
  Trust
Units (PVE.UN)
  Period
              
              High
      ($)
              
              
              Low
      ($)
              
              
              Volume
      (000's)2008January
              
              $
              10.49
              
              
              $
              8.80
              
              
              
              12,871February
              
              $
              11.37
              
              
              $
              9.83
              
              
              
              10,904March
              
              $
              11.00
              
              
              $
              9.93
              
              
              
              10,928April
              
              $
              11.54
              
              
              $
              10.76
              
              
              
              9,822May
              
              $
              12.25
              
              
              $
              10.77
              
              
              
              9,695June
              
              $
              12.20
              
              
              $
              11.19
              
              
              
              8,644July
              
              $
              11.66
              
              
              $
              10.00
              
              
              
              6,748August
              
              $
              11.39
              
              
              $
              10.30
              
              
              
              9,594September
              
              $
              11.11
              
              
              $
              8.71
              
              
              
              9,927October
              
              $
              9.55
              
              
              $
              5.18
              
              
              
              15,164November
              
              $
              7.75
              
              
              $
              5.19
              
              
              
              8,199December
              
              $
              6.00
              
              
              $
              4.68
              
              
              
              8,417
  - 27
-
 
 8.75 Percent
Debentures (PVE.DB.A)(1)
  Period
              
              High
      ($)
              
              
              Low
      ($)
              
              
              Volume2008January
              
              $
              101.05
              
              
              $
              100.02
              
              
              
              1,360February
              
              $
              102.00
              
              
              $
              101.07
              
              
              
              1,420March
              
              $
              102.02
              
              
              $
              101.77
              
              
              
              640April
              
              $
              108.50
              
              
              $
              102.02
              
              
              
              12,230May
              
              $
              110.20
              
              
              $
              106.00
              
              
              
              12,645June
              
              $
              110.00
              
              
              $
              102.01
              
              
              
              12,570July
              
              $
              103.60
              
              
              $
              103.50
              
              
              
              290August
              
              $
              103.60
              
              
              $
              103.50
              
              
              
              480September
              
              $
              101.50
              
              
              $
              100.00
              
              
              
              550October
              
              $
              100.02
              
              
              $
              91.02
              
              
              
              1,900November
              
              $
              99.52
              
              
              $
              97.54
              
              
              
              2,250December
              
              $
              99.75
              
              
              $
              92.02
              
              
              
              1,720Note:
                (1)
      In 2008, the Trust repaid $19.9 million to the holders of the 8.75 Percent
      Debentures, which matured on
                December
      31, 2008. No 8.75 Percent Debentures remain outstanding as of the
      date hereof.
 8
Percent Debentures (PVE.DB.B)
  Period
              
              High
      ($)
              
              
              Low
      ($)
              
              
              Volume2008January
              
              $
              101.05
              
              
              $
              100.00
              
              
              
              8,440February
              
              $
              101.80
              
              
              $
              101.52
              
              
              
              380March
              
              $
              103.27
              
              
              $
              101.50
              
              
              
              2,800April
              
              $
              106.27
              
              
              $
              102.50
              
              
              
              1,860May
              
              $
              106.27
              
              
              $
              103.27
              
              
              
              4,130June
              
              $
              104.06
              
              
              $
              102.00
              
              
              
              3,220July
              
              $
              103.00
              
              
              $
              101.87
              
              
              
              11,270August
              
              $
              101.92
              
              
              $
              101.89
              
              
              
              3,260September
              
              $
              102.00
              
              
              $
              101.54
              
              
              
              2,620October
              
              $
              101.52
              
              
              $
              95.50
              
              
              
              6,060November
              
              $
              98.00
              
              
              $
              95.50
              
              
              
              7,900December
              
              $
              97.50
              
              
              $
              93.01
              
              
              
              2,600
 Initial
6.5 Percent Debentures (PVE.DB.C)
  Period
              
              High
      ($)
              
              
              Low
      ($)
              
              
              Volume2008January
              
              $
              96.50
              
              
              $
              92.12
              
              
              
              17,770February
              
              $
              99.88
              
              
              $
              93.48
              
              
              
              24,740March
              
              $
              99.24
              
              
              $
              96.26
              
              
              
              8,940April
              
              $
              98.73
              
              
              $
              97.00
              
              
              
              25,280May
              
              $
              99.50
              
              
              $
              95.03
              
              
              
              16,210June
              
              $
              99.85
              
              
              $
              97.39
              
              
              
              48,720July
              
              $
              99.85
              
              
              $
              97.01
              
              
              
              73,650August
              
              $
              99.49
              
              
              $
              98.25
              
              
              
              44,800September
              
              $
              98.83
              
              
              $
              92.04
              
              
              
              54,990October
              
              $
              95.00
              
              
              $
              73.00
              
              
              
              14,080November
              
              $
              79.45
              
              
              $
              63.00
              
              
              
              9,450December
              
              $
              69.00
              
              
              $
              50.01
              
              
              
              19,630
 Supplemental 6.5 Percent
Debentures (PVE.DB.D)
  Period
              
              High
      ($)
              
              
              Low
      ($)
              
              
              Volume2008January
              
              $
              96.97
              
              
              $
              92.50
              
              
              
              23,810February
              
              $
              97.15
              
              
              $
              95.03
              
              
              
              20,970March
              
              $
              99.00
              
              
              $
              96.26
              
              
              
              18,400April
              
              $
              99.47
              
              
              $
              97.25
              
              
              
              11,050May
              
              $
              99.98
              
              
              $
              97.12
              
              
              
              25,630June
              
              $
              100.87
              
              
              $
              97.50
              
              
              
              87,850July
              
              $
              101.96
              
              
              $
              97.51
              
              
              
              18,180August
              
              $
              100.99
              
              
              $
              98.75
              
              
              
              7,380September
              
              $
              100.50
              
              
              $
              93.51
              
              
              
              12,870October
              
              $
              97.00
              
              
              $
              72.00
              
              
              
              12,100November
              
              $
              87.50
              
              
              $
              70.02
              
              
              
              10,110December
              
              $
              77.00
              
              
              $
              62.02
              
              
              
              18,460
  - 28
-
  New
York Stock Exchange
  Trust
Units (PVX)
  Period
              
              High
      (U.S.$)
              
              
              Low
      (U.S.$)
              
              
              Volume
      (000's)2008January
              
              $
              10.60
              
              
              $
              8.50
              
              
              
              29,674February
              
              $
              11.28
              
              
              $
              9.89
              
              
              
              22,016March
              
              $
              11.15
              
              
              $
              9.66
              
              
              
              22,842April
              
              $
              11.50
              
              
              $
              10.50
              
              
              
              21,081May
              
              $
              12.40
              
              
              $
              10.55
              
              
              
              29,317June
              
              $
              11.97
              
              
              $
              11.01
              
              
              
              26,743July
              
              $
              11.50
              
              
              $
              9.80
              
              
              
              27,753August
              
              $
              10.65
              
              
              $
              9.71
              
              
              
              19,459September
              
              $
              10.34
              
              
              $
              8.50
              
              
              
              29,405October
              
              $
              9.00
              
              
              $
              4.31
              
              
              
              70,648November
              
              $
              6.66
              
              
              $
              4.05
              
              
              
              37,426December
              
              $
              4.89
              
              
              $
              3.64
              
              
              
              39,266
 
 RECORD
OF CASH DISTRIBUTIONS
  The
following table sets forth the per Trust Unit amount of monthly cash
distributions declared and paid by the Trust since its inception.
  Distribution
      Amount
                  (Cdn$)
              
              
              Distribution
      Amount
                  (US$)(1)2001
                March
      - December
              
              $
              2.54
              
              
              $
              1.642002
                January
      - December
              
              $
              2.03
              
              
              $
              1.292003
                January
      - December
              
              $
              2.06
              
              
              $
              1.472004January
      - December
              
              $
              1.44
              
              
              $
              1.102005January
      - December
              
              $
              1.44
              
              
              $
              1.202006January
      - December
              
              $
              1.44
              
              
              $
              1.262007January
      - December
              
              $
              1.44
              
              
              $
              1.352008January
      - December
              
              $
              1.38
              
              
              $
              1.292009January
              
              $
              0.09
              
              
              $
              0.07February
              
              $
              0.06
              
              
              $
              0.05March
              
              $
              0.06
              
              
              $
              0.05Total
      to date for 2009
              
              $
              0.21
              
              
              $
              0.17
  Since its
inception, the Trust has paid an aggregate of $13.98 (U.S.$10.77) in cash
distributions to Unitholders.
  Note:
 (1)
              The
      exchange rate is based on the Bank of Canada noon rate on the payment
      date.
  - 29
-
 
  PREMIUM
DISTRIBUTION, DISTRIBUTION REINVESTMENT
  AND
OPTIONAL UNIT PURCHASE PLAN
  The Trust
has implemented a premium distribution, distribution reinvestment and optional
unit purchase plan (the "DRIP") to provide holders of Trust Units with a means
to automatically reinvest sums received on account of distributions on Trust
Units. Provident reserves the right to prorate the participation in the DRIP to
manage the amount of cash reinvested in the Trust and the Trust Units issued
under the DRIP. Computershare Trust Company of Canada, as Plan Agent, may at the
election of a participant (a) purchase Trust Units with the cash
distributions at 95 percent of the market value of the Trust Units, or
(b) elect to purchase additional Trust Units with the cash distributions
and deliver such Trust Units to a broker in exchange for a premium cash
distribution equal to an amount up to 102 percent of the monthly cash
distribution, or (c) purchase new Trust Units under the optional unit purchase
plan at a subscription price of 100 percent of the average market price of the
Trust Units.  If a participant has elected either (a) or (b), the Plan
Agent may, on behalf of such participant, purchase additional Trust Units with
the cash distributions at the market value of such Trust Units. Residents of
Canada are eligible to elect options (a), (b), or (c). Due to regulatory
restrictions, residents of the United States are eligible to elect option (a)
only at this time.  Employees of Provident, including the Named
Executive Officers, are entitled to participate in the DRIP.
  The Plan
was implemented in May 2002. The following table provides the details of the
DRIP since January 2007.
  Premium
                Distribution
              5
      percent Discounted Unit Price for
                Distribution
      Reinvestment Purchase PlansPayable
      Date
              Regular
                Distribution
              102
      percent of Regular
                Distribution(1)
              15
      Day Weighted
                Average
      Unit
                Price(2)
              5
      percent Discounted
                Unit
      Price13-Mar-09
              $0.06
              $0.0612
              $3.3584
              $3.190513-Feb-09
              $0.09
              $0.0918
              $5.5381
              $5.621215-Jan-09
              $0.09
              $0.0918
              $5.6991
              $5.414115-Dec-08
              $0.09
              $0.0918
              $5.4147
              $5.144014-Nov-08
              $0.12
              $0.1224
              $7.2646
              $6.901415-Oct-08
              $0.12
              $0.1224
              $8.3030
              $7.887915-Sept-08
              $0.12
              $0.1224
              $10.6818
              $10.147715-Aug-08
              $0.12
              $0.1224
              $10.5688
              $10.040415-July-08
              $0.12
              $0.1224
              $11.0744
              $10.520713-Jun-08
              $0.12
              $0.1224
              $11.5608
              $10.982815-May-08
              $0.12
              $0.1224
              $11.2476
              $10.685215-Apr-08
              $0.12
              $0.1224
              $11.0007
              $10.450714-March-08
              $0.12
              $0.1224
              $10.6251
              $10.093815-Feb-08
              $0.12
              $0.1224
              $10.1047
              $9.599515-Jan-08
              $0.12
              $0.1224
              $10.0892
              $9.584714-Dec-07
              $0.12
              $0.1224
              $10.3798
              $9.8608
  - 30
-
  Premium
                  Distribution
                5
      percent Discounted Unit Price for
                  Distribution
      Reinvestment Purchase PlansPayable
      Date
                Regular
                  Distribution
                102
      percent of Regular
                  Distribution(1)
                15
      Day Weighted
                  Average
      Unit
                  Price(2)
                5
      percent Discounted
                  Unit
      Price
 15-Nov-07
              $0.12
              $0.1224
              $12.2344
              $11.622715-Oct-07
              $0.12
              $0.1224
              $12.5390
              $11.912114-Sept-07
              $0.12
              $0.1224
              $12.1125
              $11.506915-Aug-07
              $0.12
              $0.1224
              $12.3412
              $11.724113-Jul-07
              $0.12
              $0.1224
              $12.6583
              $12.025415-Jun-07
              $0.12
              $0.1224
              $12.6321
              $12.000515-May-07
              $0.12
              $0.1224
              $13.0121
              $12.361513-Apr-07
              $0.12
              $0.1224
              $12.7197
              $12.083715-Mar-07
              $0.12
              $0.1224
              $12.3966
              $11.776815-Feb-07
              $0.12
              $0.1224
              $12.3681
              $11.749715-Jan-07
              $0.12
              $0.1224
              $12.2272
              $11.6158


Notes:
  (1)
              If,
      in respect of any distribution payment date, fulfilling all of the
      elections under the DRIP would result in Provident exceeding either the
      limit on new equity set by Provident or the aggregate annual limit on new
      Trust Units issuable pursuant to optional cash payments, then elections
      for the purchase of new Trust Units on that distribution payment date will
      be accepted: (i) first, from participants electing to reinvest their cash
      distributions in new Trust Units under the distribution reinvestment
      component of the DRIP; (ii) second, from participants electing to make
      optional cash payments; and (iii) third, from participants electing to
      receive the premium distributions. If Provident is not able to accept all
      elections in a particular category, then purchases of Trust Units in that
      category on the applicable distribution payment date will be prorated
      among all participants in that category according to the number of
      additional Trust Units sought to be purchased.  Therefore,
      amounts shown in the table represent maximum amounts payable and actual
      amounts paid may be less due to
proration.
  (2)              
This is the price used for purchases made under the DRIP.
  Materials
relating to the DRIP are available on SEDAR at www.sedar.com or the Trust's
website at www.providentenergy.com or by contacting Provident by phone at
(403) 296-2233 or by mail at 2100, 250 - 2nd Street
S.W., Calgary, Alberta T2P 0C1.
   DIRECTORS
AND OFFICERS
  The
following are the names and municipality of residence of the directors and
officers of PEL, their principal position with PEL and their principal
occupations.  The Trust does not have any directors or
officers.  All of the persons listed below have been engaged for more
than five years in their present principal occupation or executive position with
the same or associated companies except as indicated below.  Each of
the directors below will remain in office until the next annual meeting of
Unitholders scheduled on May 7, 2009.
  Name
      and Background
              
              Number
      of Trust Units
                  Beneficially
      Owned
                  or
      Controlled or DirectedJohn
      B. Zaozirny(2)
      of Calgary, Alberta is Chairman of the Board.  He also serves as
      vice-chairman and director of Canaccord Capital Inc.  He has
      been a director of PEL since 2001 and is also a director of Bankers
      Petroleum Ltd., Bayou Bend Petroleum Ltd., Canadian Oil Sands Trust,
      Coastal Energy Company, Computer Modelling Group Ltd. and Pacific Rubiales
      Energy Corp. and is chair and director of Terravest Income Fund and
      vice-chair and lead independent director of Pengrowth Energy
      Trust.
              
              93,669Grant
      D. Billing(2)
      of Calgary, Alberta is the Chairman and Chief Executive Officer and a
      director of Superior Plus Corp., a diversified company, since
      1998.  He has been a director of PEL since
      2001.
              
              100,000(4)
  - 31
-
  Name
      and Background
                
                Number
      of Trust Units
                    Beneficially
      Owned
                    or
      Controlled or Directed
 Thomas
      W. Buchanan of Calgary, Alberta has been the Chief Executive
      Officer and a director of PEL since March 2001.  Mr.
      Buchanan has also been the President of PEL since June 30,
      2006.  Prior thereto he was Executive Vice President Corporate
      Development and Chief Financial Officer of Founders Energy Ltd. from
      October 1999 to March 2001.  He is also a director of Churchill
      Energy Inc.
                
                951,145(4)
 Hugh
      A. Fergusson(1)(3)
      of Calgary, Alberta is the former Vice President and Director with Dow
      Chemical Canada Inc.  He has been a director of PEL since
      2005 and is also a director of Altagas Income Trust and Canexus Income
      Fund.
              
              9,950(4)Randall
      J. Findlay(3)of Calgary, Alberta has been a director of PEL since March
      2001.  Mr. Findlay was also the President of PEL from March
      2001 until June 30, 2006.  Prior thereto he was Executive Vice
      President and Chief Operating Officer of Founders Energy Ltd. from
      December 1999 to March 2001.  He is also a director of Canadian
      Helicopters Income Fund, Pembina Pipelines Income Fund, Superior Plus
      Corp. and Wellpoint Systems Inc.
              
              747,378Norman
      R. Gish(2)
      of Calgary, Alberta is an independent businessman.  He is also a
      director of Superior Plus Corp., and chairman and director of Railpower
      Technologies Corp. Previously, President of Gish Consulting Inc. (energy
      consulting) from 2001 to 2007 and a director of Noranda Inc. (mining) from
      2001 until its merger with Falconbridge Limited (mining), then a director
      of Falconbridge Limited until its acquisition by Xstrata plc., in
      2006.
              
              7,000(4)Bruce
      R. Libin(1)(3)
      of Calgary, Alberta is the Executive Chairman and Chief Executive Officer
      of Destiny Resource Services Corp., a resource services company, since
      December 2000.  He has also been President of B.R. Libin Capital
      Corp., an investment, merchant banking and investment banking advisory
      services company since 1995.  He has been a director of PEL
      since 2001 and is also Chairman of Winstar Resources
      Ltd.
              
              164,120Dr.
      Robert W. Mitchell(3)
      of Calgary, Alberta has been an independent businessman since September
      2003.  From 1984 to September 2003, he was Executive Vice
      President of Talisman Energy Inc., a public oil and gas
      company.  He has been a director of PEL since 2004 and is
      also a director of Winstar Resources Ltd.
              
              26,000M.H.
      (Mike) Shaikh(1)
      of Calgary, Alberta is a chartered accountant.  He has been a
      director of PEL since 2001 and is also a director of Churchill Energy
      Inc. and BNP Resources Inc.
              
              162,972(4)Jeffrey
      T. Smith(2)(3)
      of Calgary, Alberta is an independent businessman.  He has been
      a director of PEL since 2001 and is also a director of Compton
      Petroleum Ltd.
              
              10,900
 Notes:
  (1)      Member
of the Audit Committee.
 (2)      Member
of the Governance, Human Resources and Compensation Committee.
 (3)      Member
of the Reserves, Operations and Environment, Health and Safety
Committee.
 (4)      Mr.
Billing also holds $500,000 principal amount of the Initial 6.50 Percent
Debentures and $330,000 of the 8 Percent Debentures.  Mr. Buchanan
also holds $100,000 of the Supplemental 6.50 Percent
Debentures.  Mr. Shaikh also holds $250,000 principal amount of
the Supplemental6.50
Percent Debentures. Mr. Gish also holds $110,000 principal amount of the
Supplemental 6.50 Percent Debentures.
 
 Murray
N. Buchanan
  Co-President,
Midstream Business Unit
  Mr.
Buchanan received his masters of business administration from Queen's
University, as well as an honours bachelor of administration degree from Queen's
University.  Mr. Buchanan is responsible for commercial activities
associated with Provident's midstream services business unit including natural
gas liquids fractionation, storage, processing, marketing and transportation
services. Mr. Buchanan joined Provident in 2005 following Provident's
acquisition of the Empress midstream assets and related
  - 32
-
 
 marketing
entity, Kinetic Resources, where he held the position of President for eight
years.  Mr. Buchanan has over 25 years of NGL marketing and petroleum
industry experience.
  Andrew
G. Gruszecki
  Co-President,
Midstream Business Unit
  Mr. Gruszecki
received his honours bachelor of science in science from the University of
Western Ontario and did his co-op master's of business administration at
McMaster University and joined Provident in 2003.  He brings over 25
years of experience and expertise in oil and NGL marketing, business
development, and planning.  From 2000 to 2003, he was senior manager
of commercial operations at Williams Energy (Canada).  Prior to
joining Williams, Mr. Gruszecki was vice president of NGL Marketing for
Coast Energy Canada.  From 1997 to 1998, he was director of commercial
operations at TransCanada Midstream and the former Novagas
Canada.  While at Novagas, Mr. Gruszecki oversaw commercial
issues related to the planning, construction and implementation of the NGL
business which included the construction of the Redwater fractionation
facilities.  Mr. Gruszecki began his career in the energy
business in 1981 and held positions of increasing responsibility before joining
Novagas in 1997.
  David
I. Holm
  Executive
Vice President, Finance, Strategy and Business Development and Corporate
Secretary
  Mr. Holm
received his Bachelor of Commerce Degree from the University of Alberta and his
Bachelor of Laws Degree from the University of Western Ontario.  He
was called to the Alberta Bar in 1986.  Mr. Holm has spent six years
as a senior banker and most recently was Managing Director, North American
Energy with TD Securities Inc. prior to joining Provident in 2006. Prior to his
move into investment banking, Mr. Holm practiced securities law for 15 years,
most recently as a partner with Macleod Dixon llp.
  Gary
R. Kline
  Senior
Vice President, Commercial Development and Risk Management
  Mr. Kline
received his bachelor of arts in economics from the University of
Calgary.  He later received his Canadian Securities Certificate from
the Canadian Securities Institute.  Mr. Kline has over 20 years
of experience in the energy industry and before joining Provident in 2003, he
was president of GRK Energy Consulting from 1998 to
2003.  Mr. Kline has held a number of senior management positions
including managing director of marketing and business development for Reliant
Energy Canada from 1998 to 2002, vice president for natural gas and electricity
at U.S. Generating Canada from 1996 to 1998, and manager of gas marketing at
CanStates Gas Marketing from 1986 to 1996.  Mr. Kline began his energy
industry career as a regulatory analyst at TransCanada Pipelines in
1982.
  Daniel
J. O'Byrne
  Executive
Vice President, Operations and Chief Operating Officer
  Mr.
O'Byrne received his Bachelor of Science Degree in Petroleum Engineering from
the University of Alberta and a Masters of Business Administration Degree from
the University of Western Ontario.  Mr. O'Byrne has over 25 years of
diverse experience in the international and North American oil industry and has
participated in major projects in Canada, the United Kingdom (North Sea), the
Middle East, West Africa and other countries.  Mr. O'Byrne held
various executive positions with Nexen and its predecessor, Canadian Occidental
Petroleum Ltd. from 1997 to 2005 at which time he joined
Provident.  He is also a former director of the
Petroleum Technology Research Centre, a director of Unbridled Energy Ltd., and a
past chair of the Canadian Oil Sands Network for Research and
Development.  He has contributed to the reserves and safety committees
of the Canadian Association of Petroleum Producers, is a member
 
 - 33
-
 
 of the
Association of Professional Engineers, Geologists and Geophysicists of Alberta
and is one of the Society of Petroleum Engineers published authors.
  Lynn
M. Rannelli
  Assistant
Corporate Secretary
  Ms.
Rannelli received her Business Management Certificate from the University of
Calgary.  Ms. Rannelli joined Provident in 2001, following the
acquisition of Maxx Petroleum Ltd. and has over 20 years of experience in
Corporate Administration, Human Resources, Records Management, Investor
Relations and Communications.  Ms. Rannelli is a member of the
Canadian Society of Corporate Secretaries.
  Cameron
G. Vouri
  President,
Upstream Business Unit
  Mr. Vouri
obtained a Bachelor of Science (Petroleum Engineering) degree from New Mexico
Institute of Mining and Technology in 1988.  Prior to Mr. Vouri's
appointment to his current position with Provident, he was Vice President and
Chief Operating Officer of Provident since January 2003.  Prior
thereto he held the position of Vice President with
Provident.  Mr. Vouri held various senior management positions
with Koch Exploration Canada, Ltd. from 1989 to 2000 at which time he joined
Founders.
  Mark
N. Walker
  Senior
Vice President, Finance and Chief Financial Officer
  Mr. Walker
received his Bachelor of Commerce in Accounting from the University of Calgary
and later received his Certified Management Accountant
designation.  Mr. Walker began his career in 1988 and held positions
of increasing responsibility prior to joining Founders Energy in 1996 as
Controller. Prior to the appointment to his current position, Mr. Walker was
Vice President Finance and Chief Financial Officer of Provident since March
2001. Mr. Walker has over 20 years of experience in petroleum finance and
accounting.
  Committees
of the Board
  During
the year ended December 31, 2008, the Board of Directors had three standing
committees – the Audit Committee, the Reserves, Operations and Environmental,
Health and Safety Committee and the Governance, Human Resources and Compensation
Committee.  In addition, the Trust has established one additional
committee in 2006 – the Disclosure Committee, which is comprised entirely of
members of management.  Membership in each committee is set forth
below.
  Audit
Committee
  The Audit
Committee consists of Mr. M.H. (Mike) Shaikh (Chairman), Mr. Bruce R. Libin and
Mr. Hugh A. Fergusson. All members of the Audit Committee are independent and
financially literate, as determined by applicable securities legislation, and at
least one member of the Committee is an "audit committee financial expert" as
required by U.S. securities laws. The Audit Committee reviews the Trust's
interim unaudited consolidated financial statements and annual audited
consolidated financial statements and certain corporate disclosure documents
including management's discussion and analysis and annual and interim earnings
press releases before they are approved by the board of
directors.  The Committee
  
 - 34
-
 
 also
reviews and makes a recommendation to the board of directors in respect of the
appointment and compensation of the external auditor and it monitors accounting,
financial reporting, control and audit functions.  The Audit Committee
meets to discuss and review the audit plans of external auditors and is directly
responsible for overseeing the work of the external auditor with respect to
preparing or issuing the auditor's report or the performance of other audit,
review or attest services, including the resolution of disagreements between
management and the external auditor regarding financial
reporting.  The Committee questions the external auditor independently
of management and reviews a written statement of its independence based on the
criteria found in the recommendations of the Canadian Institute of Chartered
Accountants.  The Committee must be satisfied that adequate procedures
are in place for the review of the Trust's public disclosure of financial
information extracted or derived from its financial statements and it
periodically assesses the adequacy of those procedures. The Audit Committee also
must approve or pre-approve, as applicable, any non-audit services to be
provided to the Trust by the external auditor. In addition, it reviews and
reports to the board of directors on Provident's risk management policies and
procedures and reviews the internal control procedures to determine their
effectiveness and to ensure compliance with the Trust's policies and avoidance
of conflicts of interest.  In conjunction with the Trust's
whistleblower policy, the Committee has established procedures for dealing with
complaints or confidential submissions which come to its attention with respect
to accounting, internal accounting controls or auditing matters.  See
"Audit Committee Information" and Schedule A of this Annual Information
Form for additional information relating to the Audit Committee.
  Governance,
Human Resources and Compensation Committee
  The
Governance, Human Resources and Compensation Committee consists of Mr. Norman
Gish, (Chairman), Mr. Grant D. Billing, Mr. Jeffrey T. Smith and Mr. John B.
Zaozirny, all of whom are considered independent directors within the meaning of
applicable securities legislation. The Committee is responsible for recommending
to the board of directors suitable candidates for director
positions.  The selection assessment includes a wide array of factors
deemed appropriate, all in the context of an assessment of the perceived needs
of the board of directors and Provident at the time.  In addition, the
Committee assists the board of directors on corporate governance matters and in
assessing the functioning and effectiveness of the Board.
  The
Governance, Human Resources and Compensation Committee's mandate also includes
reviewing Provident's human resources policies and procedures and compensation
and incentive programs.  The Committee is responsible for assessing
senior management's performance and recommending senior management compensation
to the board of directors.  The Committee reviews the adequacy and
form of directors' compensation and makes recommendations designed to ensure
that directors' compensation adequately reflects the responsibilities of the
board of directors.  The Committee also administers the incentive
plans of the Trust and makes recommendations to the board of directors
respecting grants of awards thereunder.
  Reserves,
Operations, Environment, Health and Safety Committee
  The Reserves, Operations and Environmental, Health and Safety
Committee consists of Mr. Jeffrey T. Smith (Chairman), Dr. Robert Mitchell, Mr.
Bruce R. Libin, Mr. Hugh A. Fergusson and Randall J. Findlay, all of whom are
considered independent directors, other than Mr. Findlay, within the
meaning of applicable securities legislation.  The Committee assists
the board in its oversight of the oil and natural gas reserves evaluation
process and the public disclosure of reserves data and related information as
required by National Instrument 51-101; the operations of Provident, including
operating activities, operating expenses and capital expenditure budget; and the
environmental, health and safety issues, including the evaluation of Provident's
programs, controls and reporting systems, and compliance with applicable laws,
rules and regulations.
  
 Disclosure
Committee
  The
Disclosure Committee is comprised of the President and Chief Executive Officer,
the Executive Vice President, Operations and Chief Operating Officer, the
Executive Vice President, Finance and Strategy and Corporate Secretary, the
Senior Vice President, Finance and Chief Financial Officer, the Vice President
and Controller, the Senior Manager, Investor Relations and Communications and
the Assistant Corporate Secretary of PEL.
  - 35
-
  The
Disclosure Committee's primary responsibilities are to oversee the Trust's
disclosure practices and to ensure the Trust meets all Canadian and U.S.
regulatory disclosure requirements.  In particular, the Disclosure
Committee will review and, as necessary, help revise the Trust's controls and
other procedures to ensure that information required to be disclosed to
securities regulators and the Toronto Stock Exchange and New York Stock
Exchange, and other information the Trust will disclose to the public is
recorded, processed, summarized and reported accurately and on a timely
basis.  In addition, the Committee will determine when events,
developments, changes or other facts constitute material information or a
material change in the affairs of Provident and will review and supervise the
preparation of the Trust's (i) Annual Information Form, Information
Circular, annual and interim financial statements and any other information
filed with the Canadian and U.S. securities regulators; (ii) press releases
containing financial information, earnings guidance, forward looking statements,
information about operations, or any other information material to the Trust's
security holders; (iii) correspondence broadly disseminated to
shareholders; and (iv) other relevant written and oral communications or
presentations.
  The
Committee will also review risk factors, underlying assumptions and forward
looking statement language for written and oral communications which contain
forward looking information and review that there is a reasonable basis for any
conclusions, forecasts or projections contained in such
information.
  Conflicts
of Interest
  The
directors and officers of PEL are engaged in and will continue to engage in
other activities in the energy industry and, as a result of these and other
activities, the directors and officers of PEL 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 shall disclose his interest in such contract or agreement and shall
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.
  As at the
date hereof, PEL is not aware of any existing or potential material
conflicts of interest between PEL and a director or officer of
PEL.
  AUDIT
COMMITTEE INFORMATION
  Composition
of the Audit Committee
  The Audit
Committee consists of three members, all of whom are independent and financially
literate, as defined by National Instrument 52-110 Audit
Committees.
  Audit
Committee Charter
  The full
text of the Trust's Audit Committee Charter is set forth in Schedule A of
this Annual Information Form.
  Relevant
Education and Experience of Each Audit Committee Member
  The
following table sets out the relevant education and experience of each of the
members of the Audit Committee:
  - 36
-
  Name
              Independent
              Financially
                  Literate
              Relevant
      Education and ExperienceM.H.
      (Mike) Shaikh, FCA
              Yes
              Yes
              Mr.
      Shaikh holds the degree of Bachelor of Commerce and is a Chartered
      Accountant.  As a Chartered Accountant, Mr. Shaikh attained
      experience in preparing, auditing, analyzing and evaluating financial
      statements.  Mr. Shaikh has an understanding of the accounting
      principles used by Provident as well as the implications of those
      accounting principles on Provident's financial results.  Mr.
      Shaikh has also obtained significant financial experience and exposure to
      accounting and financial issues as the President of M.H. Shaikh
      Professional Corporation and in his role as a director and audit committee
      member of various public companies.  He was also a board member
      of the Alberta Securities Commission from 2003 to 2006.Bruce
      R. Libin, Q.C.
              Yes
              Yes
              Mr.
      Libin holds the degree of Bachelor of Commerce (Honours), Master of
      Business Administration and Juris Doctoris.  Mr. Libin has
      obtained significant financial experience and exposure to accounting,
      disclosure, internal controls and financial issues during his legal
      practice, his business experience (including as Chief Executive Officer of
      Beau Canada Exploration Ltd. and as Executive Chairman and Chief Executive
      Officer of Destiny Resource Services Corp.) and his service on the audit
      committee of several boards of directors, including Amoco Canada Petroleum
      Company Limited, Maxx Petroleum Ltd., Mark's Work Warehouse Ltd., Calgary
      Health Region, Southern Alberta Institute to Technology, NQL Drilling
      Tools Ltd., and Winstar Resources Ltd.Hugh
      A. Fergusson, LLB
              Yes
              Yes
              Mr.
      Fergusson holds the degrees of Bachelor of Arts and Bachelor of
      Laws.  He has also completed Advanced Management Programs at the
      University of Western Ontario and Northwestern University.  He
      is an independent businessman and Corporate Director.  Mr.
      Fergusson practiced law for five years following which he was employed by
      the Dow Chemical Company (and related companies) for 27 years until he
      retired in 2004.  During his career with Dow, Mr. Fergusson
      obtained significant financial experience and exposure to accounting and
      financial issues through a series of roles including commercial and
      business leadership largely related to hydrocarbons and
      energy.  In addition to being a director of a number of Dow
      subsidiaries, Mr. Fergusson was Chairman of Petromont Inc. from 2002 until
      2004 and a member of its Audit Committee from 2002 until
    2004.
  - 37
-
 External
Auditor Service Fees
  The
following table sets forth information about the fees billed to the Trust and
its Canadian and U.S. subsidiaries for professional services provided by
PricewaterhouseCoopers llp during fiscal 2008 and
2007.  PricewaterhouseCoopers llp is independent in accordance with
the auditor's rules of professional conduct in Canada.
  (CDN$)
              
              2008
              
              
              2007Audit
      Fees
              
              $
              1,119,000
              
              
              $
              2,893,800Audit-Related
      Fees
              
              
              131,000
              
              
              
              590,600Tax
      Fees
              
              
              197,920
              
              
              
              675,900All
      Other Fees
              
              
              315,063
              
              
              
              173,300Total
              
              $
              1,762,983
              
              
              $
              4,333,600
 
 Audit
Fees
  Fees for
audit services totalled approximately $1.1 millionin 2008 and
approximately $2.9 million in 2007, including fees associated with the annual
audit, the reviews of the Trust's quarterly reports, statutory audits and
regulatory filings.  These fees include approximately $0.07 million in
2008 and $1.7 million in 2007 directly related to U.S.
operations.  Fees in 2008 have decreased as a result of the sale of
the U.S. operations.
  Audit-Related
Fees
  Fees for
audit-related services totalled approximately $0.1 million in 2008 and
approximately $0.6 million in 2007.  Audit related services include
consultations concerning documents filed with respect to audits in connection
with proposed or completed acquisitions, for 2008 and 2007 included French
translation services and for 2007 included work related to BreitBurn MLP
regarding proforma financial statement preparation, review of acquisition
documents and an audit of the benefit plan.
  Tax
Fees
  Fees for
tax services totalled approximately $0.2 million in 2008 and approximately $0.7
million in 2007.  Fees for tax services include assistance with tax
return preparation, tax planning and tax advice services.
  All
Other Fees
  Fees for
all other services totalled approximately $0.3 million in 2008 and approximately
$0.2 million in 2007 for miscellaneous consulting services primarily related to
valuations.
  In
accordance with Provident's procedures for the approval of audit and non-audit
services by PricewaterhouseCoopers llp (the "Procedures"), the Audit Committee
has pre-approved the services of external auditors listed in the
Procedures.  This general pre-approval of services set forth in the
Procedures is brought to the Audit Committee for review and renewal on an annual
basis.  Management has agreed to seek the guidance of the Chairman of
the Audit Committee if there is any ambiguity about whether a particular service
is pre-approved.
 
 In the
case of proposed engagements of PricewaterhouseCoopers llp involving services
set forth in the Procedures in which the fees for such services are expected to
exceed $100,000, specific pre-approval must be obtained from the Audit
Committee.  In these circumstances in which specific pre-approval is
required, the Audit Committee has delegated the authority to effect such
pre-approval to the Chairman of the Audit Committee.
 
 In
respect of services set forth in the Procedures in which the fees for a
particular engagement are expected to be less than or equal to $100,000, the
Chairman of the Audit Committee must be notified expeditiously of any such
services commenced by the auditors.
 
 If an
engagement with PricewaterhouseCoopers llp for a particular service is
contemplated, and is neither prohibited under the terms of the Procedures nor
covered under the range of services set forth in the Procedures, the engagement
is subject to the pre-approval of the Chairman of the Audit
Committee.
 
 - 38
-
 All
pre-approvals granted by the Chairman of the Audit Committee must be presented
to the full Audit Committee at its next meeting.
 
 Prohibited
services may not be pre-approved by the Audit Committee or pursuant to the
delegated authority granted to the Chairman of the Audit
Committee.  The Trust has complied with applicable rules regulating
the provision of non-audit services to the Trust by its external
auditor.
 
 INFORMATION
CONCERNING THE OIL AND GAS INDUSTRY
  Canadian
Government Regulation
  The oil
and natural gas industry is subject to extensive controls and regulations,
imposed by various levels of government.  Outlined below are some of
the more significant aspects of the relevant legislation and
regulations.  It is not expected that any of such controls and
regulations will affect the operations of Provident in a manner materially
different than they will affect other oil and gas companies of similar
size.
  Pricing
and Marketing - Oil
  Producers
of oil negotiate sales contracts directly with oil purchasers, with the result
that the market determines the price of oil.  Such price depends in
part on oil quality, price of competing oils, distance to market and the value
of refined products.  Oil exporters are also entitled to enter into
export contracts and export oil provided that for contracts which do not exceed
one year in the case of light crude oil and two years in the case of heavy crude
oil, an export order must be obtained from the National Energy Board prior to
the export.  Any export pursuant to a contract of longer duration must
be made pursuant to a National Energy Board export licence and Governor in
Council approval.
  Pricing
and Marketing - Natural Gas
  The price
of natural gas sold in intra-provincial and inter-provincial trade is determined
by negotiation between buyers and sellers.  Natural gas exported from
Canada is subject to regulation by the National Energy Board and the government
of Canada.  The price received by Provident depends, in part, on the
prices of competing natural gas and other substitute fuels, access to downstream
transportation, distance to markets, length of the contract term, weather
conditions, the supply and demand balance and other contractual
terms.  Exporters are free to negotiate prices with purchasers,
provided that the export contracts must continue to meet certain criteria
prescribed by the National Energy Board and the government of
Canada.  As in the case with oil, natural gas exports for a term of
less than two years must be made pursuant to a National Energy Board order and
in the case of exports for a longer duration, pursuant to a National Energy
Board licence and Governor in Council approval.
  The
government of Alberta also regulates the volume of natural gas which may be
removed from the Province for consumption elsewhere.
  The
North American Free Trade Agreement
  On
January 1, 1994 the North American Free Trade Agreement ("NAFTA") among the
governments of Canada, the United States and Mexico became
effective.  NAFTA carries forward most of the material energy terms
contained in the Canada-U.S. Free Trade Agreement.  In the context of
energy resources, Canada continues to remain free to determine whether exports
to the U.S. or Mexico will be allowed provided that the restrictions are
otherwise justified under certain provisions of the General Agreement on Tariffs
and Trade and then only if any export restrictions do not: (i) reduce the
proportion of the energy resource exported
relative to the total supply of energy resource (based upon the proportions
prevailing in the most recent 36 months); (ii) impose an export price higher
than the domestic price; or (iii) disrupt
  
 - 39
-
 
 normal
channels of supply.  All three countries are prohibited from imposing
minimum export or import price requirements.
  NAFTA
contemplates the reduction of Mexican restrictive trade practices in the energy
sector and prohibits discriminatory border restrictions and export
taxes.  The agreement also contemplates clearer disciplines on
regulators to avoid discriminatory actions and to minimize disruption of
contractual arrangements.
  Provincial
Royalties and Incentives
  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 oil and natural gas production.  Royalties payable on
production from lands other than Crown lands are determined by negotiations
between the mineral owner and the lessee.  Crown royalties are
determined by governmental regulation and are generally calculated as a
percentage of the value of the gross production, and the rate of royalties
payable generally depends in part on well productivity, geographical location,
field discovery data and the type or quality of the petroleum product
produced.
  From time
to time the governments of Canada and Alberta have established incentive
programs, which have included royalty rate reductions, royalty holidays and tax
credits for the purpose of encouraging oil and natural gas production and
enhanced production projects.
  The
Government of Alberta receives royalties on the production of natural resources
from lands in which it owns the mineral rights.  Royalties payable
pursuant to petroleum and natural gas leases with the Government of Alberta are
ad valorem royalties,
assessed on a sliding scale where the rate changes depending on oil or natural
gas prices and the level of production.  On October 25, 2007, the
Government of Alberta unveiled a new royalty regime which introduced new
royalties for conventional oil, natural gas and bitumen effective January 1,
2009.
  Under the
new royalty regime, royalties payable to the Crown in right of the Province of
Alberta (the "Crown") for conventional oil are determined based upon a sliding
rate formula containing elements that account for oil price and well
production.  Royalty rates for conventional oil range up to 50
percent, with rate caps once the price of conventional oil reaches Cdn.$120 per
barrel.
  Under the
new royalty regime, natural gas royalties are determined based upon a sliding
rate formula sensitive to price and well production, though a form of deep gas
royalty holiday has been retained and lower royalty rates apply for wells with
less productivity.  Royalty rates for natural gas range from five
percent to 50 percent with rate caps once the price of natural gas reaches
$16.00/gj.  Royalties for natural gas liquids are set at 40 percent
for pentanes and 30 percent for butanes and propane.
  In
connection with the new royalty regime, the Alberta Department of Energy also
announced its intent to implement a shallow rights reversion
program.  If this program received legislative approval, it is
proposed that, beginning in 2011, geological zones above the shallowest
productive zone of lands subject to a Crown lease would revert to the Crown in
Alberta at the expiry of the primary term of the lease or, in the case of Crown
leases already past their primary term, after notice thereof to the
lessee.
  In
November, 2008, the Government of Alberta announced an optional five year
transitional royalty program which would provide companies drilling new
conventional oil and gas wells, which are commenced between November 19, 2008
and December 31, 2013 and drilled to depths of between 1,000 to 3,500 metres,
with a one-time option to elect transitional royalty rates over the rates
applicablepursuant to the new
royalty regime.  All wells drilled for which transitional rates are
elected will revert to the new royalty regime effective January 1,
2014.
 
 - 40
-
 On March
3, 2009, the Government of Alberta announced an energy incentive program to
encourage activity in the conventional oil and gas sector in
Alberta.  The program includes provisions for a drilling royalty
credit of $200 per meter drilled on new conventional oil and natural gas wells
on Crown lands that are spud and on which drilling is finished between April 1,
2009 and before April 1, 2010.  The incentive program also provides
for a maximum royalty rate of five (5) percent applicable for 12 calendar months
or 50,000 barrels or 500 mmcf of production, whichever is reached first,
applicable to new wells on Crown lands that begin producing conventional oil and
natural gas between April 1, 2009 and March 31, 2010.
  Environmental
Regulation
  The oil
and natural gas industry is currently subject to environmental regulations
pursuant to provincial and federal legislation.  Environmental
legislation provides for restrictions and prohibitions on releases or emissions
of various substances produced in association with certain oil and gas industry
operations.  In addition, legislation requires that well and facility
sites be abandoned and reclaimed to the satisfaction of provincial
authorities.  A breach of such legislation may result in the
imposition of fines and penalties, the suspension or revocation of necessary
licenses and civil liability.
  In
December, 2002, the Government of Canada ratified the Kyoto Protocol (the
"Protocol"). The Protocol calls for Canada to reduce its emissions of greenhouse
gas, or GHGs, to 6% below 1990 "business as usual" levels between 2008 and
2012.  It remains uncertain whether the Kyoto target of 6% below 1990
GHG emission levels will be enforced in Canada.  On April 26, 2007 the
Canadian Federal Government released a "Regulatory Framework for Air Emissions",
or the Framework, which outlines proposed new requirements governing the
emission of GHGs and other industrial air pollutants, including sulphur oxides,
volatile organic compounds, particulate matter, and possibly additional
sector-specific pollutants, in accordance with the Canadian Federal Government’s
Notice of Intent to Develop and Implement Regulations and Other Measures to
Reduce Air Emissions released on October 19, 2006. The Government of Canada and
the Province of Alberta released on January 31, 2008 the final report of the
Canada-Alberta ecoENERGY Carbon Capture and Storage Task Force, which recommends
among others: (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.
  On March
10, 2008, the Government of Canada released "Turning the Corner – Taking Action
to Fight Climate Change", or Turning the Corner, which provides some additional
guidance with respect to the Government of Canada's plan to reduce GHG emissions
by 20% by 2020 and by 60% to 70% by 2050. Turning the Corner is primarily
directed towards industrial emissions from certain specified industries
including the oil sands, oil and gas and refining industries. Turning the Corner
is intended to force industry to reduce GHG emissions and to create a carbon
emissions trading market, including an offset system, to provide incentives to
reduce GHG emission and establish a market price for carbon. Turning the Corner
provides for: (i) mandatory reductions of 18% from the 2006 baseline starting in
2010 and by an additional 2% in subsequent years for existing facilities; (ii)
new facilities built between 2004 and 2011 will have mandatory emissions
standards based upon clean fuel standards (natural gas) with a 2% reduction
below the third year's intensity levels; and (iii) oil sands plants built in
2012 and later which use heavier hydrocarbons and upgraders and in situ
production will have mandatory standards in 2018 based upon carbon capture and
storage standards or other green technologies intensity. For the upstream oil
and gas industry, Turning the Corner also provides for a company threshold of
10,000 boe/day and facility threshold of 3,000 tonnes of CO2.  It
is contemplated that new regulations will take effect January 1,
2010.  Draft regulations were expected to be available for public
comment in the Fall of 2008 but now expected in mid 2009. The proposed
compliance mechanisms include an emissions credit trading system for GHGs and
certain industrial air pollutants, and several options for companies to choose
among to meet GHG emission
 
 - 41
-
  intensity
reduction targets and encourage the development of new emission reduction
technologies, including the option of making payments into a technology fund, an
emissions and offset trading system, limited credits for emission reductions
created between 1992 and 2006, and international emission credits under the
clean development mechanism under the Kyoto Protocol for up to 10% of each
firm's regulatory obligation.
  Environmental
legislation in the Province of Alberta has been consolidated into the Environmental Protection and
Enhancement Act(Alberta), theWater Act(Alberta), and the
Oil and Gas Conservation
Act (Alberta) (the "OGCA"). These statutes impose environmental
standards, require compliance, reporting and monitoring obligations, and impose
penalties. In addition, the emission reduction requirements in the Climate Change and Emissions
Management Act(Alberta) came into effect on July 1, 2007. Under this
legislation, Alberta facilities emitting more than 100,000 tonnes of GHGs a year
must reduce their emissions intensity by 12%.  Companies have four
options to choose from in order to meet the reduction requirements outlined in
this legislation, and these are: (i) by making improvement to operations that
result in reductions; (ii) by purchasing emission credits from other sectors or
facilities that have reduced their emissions below the required emission
intensity reduction levels; (iii) by purchasing off-set credits from other
sectors or facilities that have emissions below the 100,000 tonne threshold and
are voluntarily reducing their emissions in Alberta; or (iv) by contributing to
the Climate Change and Emissions Management Fund.  Companies can
choose one of these options or a combination thereof. Provident is
committed to meeting its responsibilities to protect the environment wherever it
operates and anticipates making increased expenditures of both a capital and an
expense nature as a result of the increasingly stringent laws relating to the
protection of the environment, and will be taking such steps as required to
ensure compliance with the environmental protection legislation in all
jurisdictions in which it operates. The Trust believes that it is reasonably
likely that the trend towards stricter standards in environmental legislation
and regulation will continue.
  Exports
from Canada
  In order
to export oil or natural gas from Canada, certain approvals are required from
the National Energy Board and the Government of Canada.  The
approval(s) required are dependent on the hydrocarbon substance being exported
and the length of the proposed export arrangement.
  INFORMATION
CONCERNING THE NATURAL GAS MIDSTREAM, NGL PROCESSING
 AND
MARKETING INDUSTRY
  General
  The NGL
industry involves the production, transportation and marketing of products that
are extracted from natural gas prior to its sale to end use
customers.  The profitability of the industry is based on the products
extracted being of greater economic value as separate commodities than as
components of natural gas.
  Natural
gas is a mixture of various hydrocarbon components, the most abundant of which
is methane.  The higher value hydrocarbons, which include ethane (C2),
propane (C3), butane (C4) and pentanes-plus (C5+), are generally in gaseous form
at the pressures and temperatures under which natural gas is gathered and
transported.  The basis of the NGL industry is the recovery of these
higher value hydrocarbons from natural gas for sale in a liquid
form.
  The NGL
value chain begins with the gathering of gas that is produced.  The
gas then gets processed through field processing plants, mainline extraction
facilities and fractionation facilities in order to remove
high value NGLs, as well as water, sulphur and other impurities.  The
value chain culminates with the transportation and eventual sale of NGLs to the
final customer.
  - 42
-
  NGL
Extraction
  A primary component of
the NGL value chain is the extraction
of NGLs from natural gas, which takes place in a number of steps at extraction
facilities.  NGLs are recovered primarily at three types of extraction
facilities: natural gas field plants, natural gas straddle plants and oil
refineries.  Field plants process raw natural gas, which is produced
from wells in the immediate vicinity, to remove impurities such as water,
sulphur and carbon dioxide prior to the delivery of natural gas to the major
natural gas pipeline systems.  Field plants also remove almost all
pentanes-plus and as much as 65 percent of propane and 80 percent of butane in
order to meet pipeline specifications.  The NGLs extracted are
generally removed in mixes (either ethane-plus or propane-plus ), which must be
further processed in subsequent steps to separate out the individual
products.
  NGL
Fractionation
  NGL mix
extracted at field plants is transported to fractionation facilities, which
enhances its value by separating the mix into its components: ethane, propane,
butane and pentanes-plus. Fractionation generally does not occur at field
plants, but rather at a central location.  The NGL mixes are moved by
truck or pipeline to fractionation facilities.  Once fractionated, the
products are then transported to markets in Alberta or outside the province, by
pipeline, truck or rail.
  NGL
Transportation
  The
efficient movement of NGL products in Canada requires significant
infrastructure, including transportation assets (pipelines, trucks, rail cars),
storage facilities and terminals (rail and truck).  The most efficient
and the lowest cost means for moving NGL products to markets is by
pipeline.  The Canadian NGL sector has an extensive pipeline network
for the transportation of natural gas to field plants and extraction facilities,
and NGLs to fractionation facilities, petrochemical complexes, underground
storage facilities and the final customer.  Truck and rail account for
a significant amount of the NGLs transported in Alberta, with pipelines serving
as the main mode of transport.
  NGL
Storage
  Storage
assets offer a number of key strategic advantages, which include:
(i) providing the necessary buffer between production of NGLs (which varies
daily depending on gas flows and composition) and their consumption (which can
vary from day to day and season to season depending on market needs);
(ii) allowing NGL sellers to store inventory to accommodate outages in NGL
fractionation plants; and (iii) exploiting seasonal price differentials
that may develop over the course of a year (particularly for propane and
butane).
  NGL
Marketing
  The markets for NGLs
are North American in scope with end uses varying substantially
by product.  NGLs are used directly as heating and transportation
fuels and also as a feedstock for the petrochemical and crude oil refining
industries.
  Ethane is
used primarily as feedstock for the petrochemical industry.
  Propane
is the most versatile of the NGL products from a marketing perspective. Uses for
propane include home and commercial heating, crop drying, food processing,
cooking and motor fuel.
  Butane is
used primarily in gasoline blending, either directly or in the production of
iso-octane.
  - 43
-
  Pentanes-plus
is used primarily as a diluent to blend with heavy crudes to decrease the
viscosity and density of these crudes, allowing them to be transported in
pipelines. In addition, pentanes-plus are used as a refinery feedstock in the
production of gasolines.
  Commercial
Arrangements
  An
extraction facility's fees may be based on a cost-of-service arrangement
(reimbursement for operating expenses plus a return on capital employed), a
fixed charge per unit of throughput, or some combination of these fee
structures.  In order to produce NGLs, the owner of the facility must
purchase natural gas (referred to as shrinkage gas) to replace the energy
removed from the natural gas stream in the form of NGLs as part of the
extraction process.  For the right to extract NGLs from the gas
stream, extraction facility owners generally pay the owners of the gas a premium
over the shrinkage gas price, which effectively amounts to sharing with owners
of the gas a portion of the value that is added through the recovery and sale of
NGLs.  Other costs of extraction include electrical power, labour,
maintenance, property taxes, insurance and other overhead.
  For
ethane, market prices usually consist of a shrinkage gas cost which flows
through to ethane buyers, a flow through of a portion of plant operating costs
and an additional fixed fee to cover capital employed.  As a result,
the ethane operations of an extraction facility generally generate a relatively
predictable cash flow stream.
  The
extraction facility's other revenues are often tied to the market prices of
propane, butane and pentanes-plus which in turn are typically correlated as a
percentage of the price of crude oil.
  A
fractionation facility provides a package of services, which may include
transportation of the NGL mix to the facility; fractionation of an incoming
ethane-plus or propane-plus mixture into specification ethane, propane, butane
and pentanes-plus; storage of NGLs at the facility; distribution and
terminalling of the specification products; and marketing of the products. The
fees charged vary depending upon the package of services provided. Facility
expenses include operating costs associated with gathering, transporting,
fractionating, storing and distributing the NGL mix. Hence, profit is determined
by the difference between the fees charged and the costs incurred for the
service provided rather than on the spread between natural gas and NGL prices as
in the case of an extraction plant.  The owner of a fractionator may
also purchase NGL streams in the field for its own account, transport and
process the stream, then sell the resulting products in the
market.  In this case, its profit will be the difference between the
sales prices it receives and the sum of its purchase price for the NGL stream
and its costs of production (transportation, fractionation,
storage).
  
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-
 
 RISK
FACTORS
  The Trust
Units do not represent a traditional investment in the oil and natural gas
industry.  Prospective purchasers of the Trust Units should carefully
consider the information set forth below and the other information set forth
herein before deciding to invest in the Trust Units.
  The Trust
is a limited purpose trust, which will be entirely dependent upon the operations
and assets of Provident through its ownership directly and indirectly, of the
natural gas midstream, NGL processing and marketing business and the oil and
natural gas properties.  Accordingly, the Trust is dependent upon the
ability of Provident to meet its interest and principal repayment obligations
under the notes which the Trust may issue from time to time and to pay
royalties.  Provident's income will be received from the cash flow
generated from the natural gas midstream, NGL processing and marketing business
and from the production of oil and natural gas from Provident's existing
resource properties and will be susceptible to the risks and uncertainties
associated with the oil and natural gas industry and the NGL processing business
generally.  If the oil and natural gas reserves associated with
Provident's resource properties are not supplemented through additional
development or the acquisition of additional oil and natural gas properties, the
ability of Provident to meet its obligations to the Trust may be adversely
affected.  Unitholders should consider carefully the information
contained herein and, in particular, the following risk factors:
  Oil
and Gas Production Risk Factors
  Exploration
and Development
  Exploration
and development risks are due to the uncertain results of searching for and
producing oil and natural gas using imperfect scientific
methods.  These risks are mitigated by using experienced staff,
focusing exploitation efforts in areas in which Provident has existing knowledge
and expertise or access to such expertise, using up-to-date technology to
enhance methods and controlling costs to maximize returns.  Advanced
oil and natural gas related technologies such as three dimensional seismography,
reservoir simulation studies and horizontal drilling have been used by Provident
and will be used by Provident to improve its ability to find, develop and
produce oil and natural gas.
  Operations
  Provident's
operations will be subject to all of the risks normally incident to the
operation and development of oil and natural gas properties and the drilling of
oil and natural gas wells, including encountering unexpected formations or
pressures, blowouts, craterings and fires, all of which could result in personal
injuries, loss of life and damage to property of Provident and
others.  Provident will have both safety and environmental policies in
place to protect its operators and employees, as well as to meet the regulatory
requirements in those areas where it operates.  In addition, Provident
will have liability insurance policies in place, in such amounts as it considers
adequate, however, it will not be fully insured against all of these risks, nor
are all such risks insurable.
  Continuing
production from a property, and to some extent the marketing of production
therefrom, are largely dependent upon the ability of the operator of the
property.  To the extent the operator fails to perform these functions
properly, revenue may be reduced. Payments from production generally flow
through the operator and there is a risk of delay and additional expense in
receiving such revenues if the operator becomes insolvent.  Although
satisfactory title reviews are generally conducted in accordance with industry
standards, such reviews do not guarantee or certify that a defect in the chain
of title may not
arise to defeat the claim of Provident to certain of its oil and gas
properties.  A reduction of the income from the Provident royalties
could result in such circumstances.
 
 - 45
-
 
 Oil
and Natural Gas Prices
  The price
of oil and natural gas will fluctuate throughout the life of Provident and price
and demand are factors largely beyond its control.  Such fluctuations
will have a positive or negative effect on the revenue to be received by
it.  Such fluctuations will also have an effect on the acquisition
costs of any future oil and natural gas properties that Provident may
acquire.  As well, cash distributions from the Trust will be highly
sensitive to the prevailing price of crude oil and natural gas.
  Marketing
  The
marketability and price of oil and natural gas, which may be acquired or
discovered by Provident, will be affected by numerous factors beyond its
control.  These factors include demand for oil and natural gas, market
fluctuations, the proximity and capacity of oil and natural gas pipelines and
processing equipment and government regulations, including regulations relating
to environmental protection, royalties, allowable production, pricing, importing
and exporting of oil and natural gas.
  Capital
Investment
  The
timing and amount of capital expenditures will directly affect the amount of
income for distribution to Trust Unitholders.  Distributions may be
reduced, or even eliminated, at times when significant capital or other
expenditures are made.
  Reserves
  Although
McDaniel, AJM and Provident have carefully prepared the reserve figures included
herein, such figures are estimates and no assurance can be given that the
indicated levels of reserves will be produced.  Probable reserves
estimated for properties may require revision based on the actual development
strategies employed to prove such reserves.  Declines in the reserves
of Provident, which are not offset by the acquisition, or development of
additional reserves may reduce the underlying value of Trust Units to
Unitholders.  The value of the Trust Units attributable to the oil and
gas reserves will have no value once all of the oil and natural gas reserves of
Provident have been produced.  As a result, holders of Trust Units
will have to obtain the return of capital invested out of cash flow derived from
their investment in such Trust Units.
  Competition
  The
industry is highly competitive in the acquisition of exploration prospects and
the development of new sources of production and the sale of oil and natural
gas.
  Environmental
Concerns
  The oil
and natural gas industry is subject to environmental regulation pursuant to
local, provincial and federal legislation. A breach of such legislation may
result in the imposition of fines or issuance of clean up orders in respect of
Provident or its oil and gas properties.  Such legislation may be
changed to impose higher standards and potentially more costly obligations on
Provident.  Although Provident has established a reclamation fund for
the purpose of funding its currently estimated future environmental and
reclamation obligations based on its current knowledge, there can be no
assurance that Provident will be able to satisfy its actual future
environmental and reclamation obligations. See "Information Concerning the Oil
and Gas Industry - Environmental Regulation".
  Delay
in Cash Distributions
  In
addition to the usual delays in payment by purchasers of oil and natural gas to
the operators of oil and gas properties, and by the operator to Provident,
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
  
 - 46
-
 
 connection
of wells to a gathering system, blowouts or other accidents, recovery by the
operator of expenses incurred in the operation of oil and gas properties or the
establishment by the operator of reserves for such expenses.
  Reliance
on Provident
  Unitholders
will be dependent on the management of Provident in respect of the
administration and management of all matters relating to Provident's oil and gas
properties, the royalties, the Trust and Trust Units.  Investors who
are not willing to rely on the management of Provident should not invest in the
Trust Units.
  Depletion
of Reserves
  The Trust
has certain unique attributes, which differentiate it from other oil and gas
industry participants.  Distributable Cash in respect of Provident's
oil and gas properties, absent commodity price increases or cost effective
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.  Provident will not be reinvesting cash flow in
the same manner as other industry participants. Accordingly, absent capital
injections, Provident's initial production levels and reserves will
decline.
  Provident's
future oil and natural gas reserves and production, and therefore its cash
flows, will be highly dependent on Provident's success in exploiting its reserve
base and acquiring additional reserves.  Without reserve additions through
acquisition or development activities, Provident's reserves and production will
decline over time as reserves are exploited.
  To the
extent that external sources of capital, including the issuance of additional
Trust Units (through public offerings, the DRIP or otherwise) become limited or
unavailable, Provident's ability to make the necessary capital investments to
maintain or expand its oil and natural gas reserves will be
impaired.  To the extent that Provident is required to use cash flow
to finance capital expenditures or property acquisitions, the level of
Distributable Cash will be reduced.
  There can
be no assurance that Provident will be successful in developing or acquiring
additional reserves on terms that meet the Trust's investment
objectives.
  Write-downs
of Oil and Gas Property Investments
  Lower oil
and gas prices increase the risk of write-downs of Provident’s oil and gas
property investments.  Under Canadian accounting rules, the net
capitalized cost of oil and gas properties may not exceed a "ceiling limit" that
is based, in part, upon estimated future net cash flows from
reserves.  If oil and natural gas prices decline, Provident’s net
capitalized cost may exceed this cost ceiling, ultimately resulting in a charge
against Provident’s earnings.  While these write-downs would not
affect cash flow, the charge against earnings could be viewed unfavourably in
the market.
  Regulatory
Matters
  The oil
and gas industry in Canada operates under federal, provincial and municipal
legislation and regulation governing such matters as land tenure, prices,
royalties, production rates, environmental protection controls, income, the
exportation of crude oil, natural gas and other products, as well as other
matters.  The industry is also subject to regulation by governments in
such matters as the awarding or acquisition of exploration and production rights
or other interests, the imposition of specific drilling obligations,
environmental protection controls, control over the development and abandonment
of fields (including restrictions on production) and possibly expropriation or
cancellation of contract rights.
  
 - 47
-
 
 Government
regulations may be changed from time to time in response to economic or
political conditions.  The exercise of discretion by governmental
authorities under existing regulations, the implementation of new regulations or
the modification of existing regulations affecting the oil and gas industry
could reduce demand for crude oil and natural gas, increase Provident’s costs
and have a material adverse impact on Provident.
  Before
proceeding with a project the participants in the project must obtain all
required regulatory approvals.  The regulatory approval process can
involve stakeholder consultation, environmental impact assessments and public
hearings, among other things.  In addition, regulatory approvals may
be subject to conditions including security deposit obligations and other
commitments.  Failure to obtain regulatory approvals, or failure to
obtain them on a timely basis, could result in delays and abandonment or
restructuring of the projects undertaken by Provident and increased costs, all
of which could have a material adverse affect on Provident.
  Kyoto
Protocol
  Canada is
a signatory to the United Nations Framework Convention on Climate Change and has
ratified the Kyoto Protocol established thereunder to set legally binding
targets to reduce nationwide emissions of carbon dioxide, methane and nitrous
oxide greenhouse gases.  Provident’s business and operations produce
some of the greenhouse gases covered by the Convention.  Future
federal legislation, together with provincial emission reduction requirements,
may require the reduction of emissions or emissions intensity from Provident’s
business and operations.  The reductions may not be technically or
economically feasible and the failure to meet such emissions reduction
requirements may materially adversely affect Provident’s business and result in
fines, penalties and the suspension of operations.  No assurance can
be given that future environmental approvals, laws or regulations will not
adversely impact the ability to operate Provident’s business or increase or
maintain production or will not increase unit costs of
production.  Equipment from suppliers which can meet future emission
standards may not be available on an economic basis and other methods of
reducing emissions to required levels in the future may significantly increase
operating costs or reduce output.  There is a risk that the federal
and/or provincial governments could pass legislation which would tax such
emissions or require, directly or indirectly, reductions in such emissions
produced by energy industry participants for which Provident may be unable to
mitigate.  Mitigation of the risk of future legislative or regulatory
limits on the emission of greenhouse gases may include the acquisition of
emission reduction or off set credits from third parties.  However,
emission reduction or off set credits may not be available for acquisition by
Provident or may not be available on an economic basis and may not be recognized
or qualify under future legislative or regulatory regimes as mitigation for the
emission of greenhouse gases by Provident. See "Information Concerning Oil and
Gas Industry - Environmental Regulation".
  Royalties
  Provident’s
revenue and expenses are directly affected by the royalty regimes applicable to
its oil and gas activities.  The government of the Province of Alberta
or of any other jurisdiction where Provident carries on business could adopt new
royalty regimes which will make capital expenditures uneconomic and there can be
no assurance that the regime currently in place will remain
unchanged.
  In
Alberta, the Crown royalty rates on conventional oil and natural gas fluctuate,
depending on when a well was drilled, well depth, well production volume and the
price of oil and natural gas. On October 25, 2007, the Alberta provincial
government introduced a new royalty regime which became effective on January 1,
2009 and is applicable to all existing conventional oil and natural gas wells in
Alberta. The new royalty regime assesses the applicable royalty rate on a well
by well basis using a sliding scale which takes into account the price of oil
and natural gas and well production volumes.
  
 - 48
-
 
 On
November 19, 2008 and November 24, 2008 the Alberta provincial government
announced details of an optional five year transitional royalty program that
applies to conventional oil and natural gas wells drilled to measured depths
between 1,000 to 3,500 meters between November 19, 2008 and January 1, 2014. For
each well, the Trust can make a one time election to produce the well under the
transitional royalty program or the new royalty regime. As of January 1, 2014,
all production subject to the transitional program will revert to the new
royalty regime.
  Subsequent
to these changes to the royalty structure, the Alberta provincial government has
launched a study of the competitiveness of Alberta’s conventional oil and gas
business. Terms of reference have not been made public; however, it is possible
that the royalty regime may be subject to further review.
 
 On March
3, 2009, the Alberta provincial government announced an energy
incentive program to encourage activity in the conventional oil and gas sector
in Alberta.  The program includes provisions for (a) a drilling
royalty credit of $200 per meter drilled on new conventional oil and natural gas
wells on Crown lands that are drilled between April 1, 2009 and before
April 1, 2010 and (b) a maximum royalty rate of five (5) percent applicable
for 12 calendar months, 50,000 barrels of Crown production or 500 million cubic
feet, whichever is reached first, applicable to new wells on Crown lands that
begin producing conventional oil and natural gas between April 1, 2009 and March
31, 2010.
 
 These
changes to the Alberta royalty regime, as well as the potential for changes in
the royalty regimes applicable in other provinces have created uncertainty
surrounding the ability to accurately estimate future royalties, resulting in
additional volatility and uncertainty for producers. See "Information Concerning
the Oil and Gas Industry - Provincial Royalties and Incentives".
  Aboriginal
Claims
  Aboriginal
people have claimed aboriginal title and rights to a substantial portion of
western Canada.  Provident is unable to assess the effect, if any,
that any such claim would have on its business and operations.
  Natural
Gas Midstream, NGL Processing and Marketing Business Risk Factors
  Facilities
Throughput
  The
volumes of natural gas processed through Provident's natural gas midstream, NGL
processing and marketing business and of NGLs and other products transported in
the pipelines depend on production of natural gas in the areas serviced by the
business and pipelines.  Without reserve additions, production will
decline over time as reserves are depleted and production costs may rise.
Producers may shut in production at lower product prices or higher production
costs.  Producers in the areas serviced by the business may not be
successful in exploring for and developing additional reserves, and the gas
plants and the pipelines may not be able to maintain existing volumes of
throughput. Commodity prices may not remain at a level which encourages
producers to explore for and develop additional reserves or produce existing
marginal reserves.
  The rate
and timing of production from proven natural gas reserves tied into the gas
plants is at the discretion of the producers and is subject to regulatory
constraints.  The producers have no obligation to produce natural gas
from these lands.
  Provident's
natural gas midstream, NGL processing and marketing business is connected to
various third party trunkline systems.  Operational disruptions or
apportionment on those third party systems may prevent the full utilization of
the business.
  Over the
long term, business will depend, in part, on the level of demand for NGLs and
natural gas in the geographic areas in which deliveries are made by pipelines
and the ability and willingness of shippers
  
 - 49
-
 
 having
access or rights to utilize the pipelines to supply such
demand.  Provident cannot predict the impact of future economic
conditions, fuel conservation measures, alternative fuel requirements,
governmental regulation or technological advances in fuel economy and energy
generation devices, all of which could reduce the demand for natural gas and
NGLs.
  Operational
Matters and Hazards
  Provident's
operations will be subject to common hazards of the natural gas processing and
pipeline transportation business.  The operation of Provident's
natural gas midstream, NGL processing and marketing business could be disrupted
by natural disasters or other events beyond the control of
Provident.  A casualty occurrence could result in the loss of
equipment or life, as well as injury and property damage.  Provident
carries insurance coverage with respect to some, but not all, casualty
occurrences in amounts customary for similar business operations, which coverage
may not be sufficient to compensate for all casualty occurrences.
  The
operation of Provident's natural gas midstream, NGL processing and marketing
business will involve many risks, including the breakdown or failure of
equipment, information systems or processes, the performance of equipment at
levels below those originally intended (whether due to misuse, unexpected
degradation or design, construction or manufacturing defects), failure to
maintain an adequate inventory of supplies or spare parts, operator error,
labour disputes, disputes with owners of interconnected facilities and carriers
and catastrophic events such as natural disasters, fires, explosions, fractures,
acts of eco-terrorists and saboteurs, and other similar events, many of which
are beyond the control of the Trust or Provident.  The occurrence or
continuance of any of these events could increase the cost of operating
facilities and/or reduce its processing or throughput capacity, thereby reducing
cash flow.
  Operating
and Capital Costs
  Operating
and capital costs of Provident's natural gas midstream, NGL processing and
marketing business may vary considerably from current and forecast values and
rates and represent significant components of the cost of providing
service.  In general, as equipment ages, maintenance capital
expenditures and maintenance expenses with respect to such equipment may
increase over time.  Distributions may be reduced if significant
increases in operating or capital costs are incurred.
  Although
operating costs are to be recaptured through the tariffs charged on natural gas
volumes processed and oil and NGLs transported, respectively, to the extent such
charges escalate, producers may seek lower cost alternatives or stop production
of their natural gas.
  Competition
  Provident's
natural gas midstream, NGL processing and marketing business is subject to
competition from other gas processing plants which are either in the general
vicinity of the gas plants or have gathering systems that are or could
potentially extend into areas served by the gas plants. The pipelines and
storage, terminal and processing facilities are also subject to competition from
other pipelines and storage, terminal and processing facilities in the areas
they serve, and the gas products marketing business is subject to competition
from other marketing firms.
  Producers in Alberta
compete with producers in other regions to supply natural gas and gas products
to customers in North America and the natural gas and gas products industry also
competes with other industriesto supply the fuel, feedstock and other
needs of consumers.  Such competition may have an adverse effect on
the production of natural gas and gas products in Alberta and, as a result, on
the demand for Provident's services.
  
 - 50
-
 
 Regulatory
Intervention
  Pipelines
and facilities can be subject to common carrier and common processor
applications and to rate setting by regulatory authorities in the event
agreement on fees or tariffs cannot be reached with producers.  To the
extent that producers believe processing fees or tariffs respecting pipelines
and facilities are too high, they may seek rate relief through regulatory
means.
  Environmental
Considerations
  Major
equipment failure, release of toxic substances or pipeline rupture could result
in damage to the environment and Provident's natural gas midstream, NGL
processing and marketing business, death or injury and substantial costs and
liabilities to third parties.  Provident may not be able to insure
against these events or may elect not to insure because of high premium costs or
for other reasons. If, at any time, appropriate regulatory authorities deem any
one of the gas plants unsafe, they may order it to be shut down.
  The gas
processing and gathering industry is regulated by federal and provincial
environmental legislation.  Activities that do not meet regulatory
standards or that breach such legislation may result in the imposition of fines,
penalties and suspension of operations.  It is possible that
increasingly strict environmental and safety laws will be implemented, which
could result in substantial costs of compliance.
  Abandonment
  Provident
will be responsible for compliance with all laws and regulations regarding
abandonment of Provident's natural gas midstream, NGL processing and marketing
business at the end of their economic life, which abandonment costs may be
substantial. It is not possible to estimate the abandonment costs at this time
as they will be a function of regulatory requirements at the time of
abandonment.
  Frac
Spread
 The
MidstreamBusiness
is exposed to possible price declines between the time Provident purchases NGL
feedstock and sells NGL products, and to narrowing frac spread
ratios.  Frac spread ratio is the ratio between crude oil prices and
natural gas prices.  The amount of profit or loss made on the
extraction portion of the MidstreamBusiness will generally
increase or decrease with the frac spread ratio.  The Midstream
Business is also exposed to a change in the differential between NGL product
prices and crude oil prices.  This exposure could result in material
variability of cash flow generated by the Midstream Business, which could
negatively affect the Trust and the cash distributions of the
Trust.
 Reliance
on Principal Customers and Operators
  Provident
will rely on several significant customers to purchase product from the
Midstream Business.  Ethane is predominately purchased by Nova
Chemicals Corporation and Dow Chemicals Canada Inc.  A significant
amount of propane is purchased by Ferrellgas, a division of Ferrellgas Partners
L.P. and AmeriGas Partners L.P.  EnCana Corporation and its affiliates
("EnCana") will purchase the majority of the condensate from the EnCana Empress
Debutanizer.  BP Canada operates the BP E1 Plant at Empress, Alberta
and the west to east system described herein.  If for any reason these
parties were unable to perform their obligations under the various agreements
with Provident, the revenue and distributions of the Trust, and the operations
of the MidstreamBusiness could be
negatively impacted.
  
 - 51
-
 
 General
Risk Factors
  Availability
of Credit and Debt Service
  As of
March 11, 2009, the Trust had drawn $489.2 million against its credit
facility and had $32.9 million of the credit facility drawn on letters of
credit, representing 46 percent of the credit capacity.  Variations in
interest rates and scheduled principal repayments or the need to refinance the
credit facility upon expiration could result in significant changes in the
amount required to be applied to debt service before payment of any amounts to
the Trust.  Although it is believed that the credit facilities are
sufficient, there can be no assurance that the amounts will be adequate for the
financial obligations of the Trust, that additional funds can be obtained or
that, upon expiration, the credit facility can be refinanced on terms acceptable
to the Trust or the lenders.
  The
lenders have been provided with security over substantially all of the assets of
Provident.  If Provident becomes unable to pay its debt service
charges or otherwise commits an event of default such as bankruptcy, the lenders
may foreclose on or sell Provident's oil and gas properties and other
assets.
  As a
result of the weakened global economic situation, the Trust, along
with other entities in the energy sector, may have restricted access to
capital, bank debt and equity, and is likely to face increased borrowing costs.
Although Provident's business in the energy sector, and asset base have not
changed, the lending capacity of all financial institutions has diminished and
risk premiums have increased. As future capital expenditures will be financed
out of funds generated from operations, borrowings and possible future equity
sales, the Trust's 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 the Trust's securities in particular.
  To the
extent that external sources of capital become limited or unavailable or
available on onerous terms, the Trust's ability to make capital investments,
maintain existing assets and pay distributions may be impaired, and its assets,
liabilities, business, financial condition and results of operations may be
materially and adversely affected as a result.
  Based on
current funds available and expected funds generated from operations, the Trust
believes it has sufficient funds available to fund its projected capital
expenditures. However, if funds generated from operations are lower than
expected or capital costs for these projects exceed current estimates, or
if Provident incurs major unanticipated expenses related to development or
maintenance of its existing properties, it may be required to seek additional
capital to maintain its capital expenditures at planned
levels.  Failure to obtain any financing necessary for Provident's
capital expenditure plans may result in a delay in development of
Provident's properties.
  Risks
Associated With the Level of Foreign Ownership
  Generally,
a trust cannot qualify as a "mutual fund trust" for the purposes of the Tax Act
if it is established or is being maintained primarily for the benefit of
non-residents. Although not without uncertainty, this is generally accepted to
exist in most situations where Non-Resident holders own significantly in excess
of 50 percent of the aggregate number of Trust Units issued and outstanding.
However, there is currently an exception to the non-resident ownership
restriction where not more than 10 percent of the trust's property has at any
time consisted of "taxable Canadian property".  There can be no
assurance that the treatment of mutual fund trusts will not be changed in a
manner which adversely affects Trust Unitholders.  See "Information
Concerning the Trust, PEL, PMHLP and Other Entities -
Provident Energy Trust - Limitation on Non-Resident Trust Unitholders" in this
Annual Information Form.
  - 52
-
  There
would be material adverse tax consequences if the Trust lost its status as a
mutual fund trust under Canadian tax laws
  It is
intended that the Trust continue to qualify as a mutual fund trust for purposes
of the Tax Act. The Trust may not, however, always be able to satisfy any future
requirements for the maintenance of mutual fund trust status. Should the status
of the Trust as a mutual fund trust be lost or successfully challenged by a
relevant tax authority, certain adverse consequences may arise for the Trust and
Unitholders. Some of the significant consequences of the Trust losing mutual
fund trust status are as follows:
   ·
              The
      Trust would be taxed on certain types of income distributed to
      Unitholders. 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.
   ·
              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.
   The Trust
may take certain measures in the future to the extent the Trust believes them
necessary to ensure that it maintains its status as a mutual fund trust. These
measures could be adverse to certain holders of Trust Units.
  Litigation
  The Trust
and its various subsidiaries and affiliates are, in the course of their
business, subject to lawsuits and other claims.  Defence and
settlement costs associated with such lawsuits and claims can be substantial,
even with respect to lawsuits and claims that have no merit.  Due to
the inherent uncertainty of the litigation process, the resolution of any
particular legal proceeding could have a material adverse effect on the
financial position or operating results of Provident. Quicksilver
Resources Inc. ("Quicksilver") filed a lawsuit on October 31, 2008 against
BreitBurn MLP, certain of its directors (including three Provident nominees),
and Provident. The claim relates to a transaction between BreitBurn MLP and
Quicksilver and certain other BreitBurn MLP matters. Quicksilver alleges, among
other things, that it was induced to enter into a contribution agreement
pursuant to which it contributed assets to BreitBurn MLP by false
representations as to Provident's relationship with BreitBurn MLP. The
transaction involved the issuance by BreitBurn MLP to Quicksilver of
approximately U.S.$700 million of units of BreitBurn MLP. The litigation is in
its very early stages, and it is not possible at this time to assess the
potential exposure of Provident in the event of an adverse verdict. Provident
believes the claims made against it in the lawsuit are without merit and will
vigorously defend itself and its named director nominees against these
claims.
 Changes
in Legislation
  There is
no assurance that Canadian federal income tax laws, including the treatment of
mutual fund trusts thereunder, will not be changed in a manner that affects
Unitholders in a material adverse way.  See "Information Concerning
the Trust, PEL, PMHLP and Other Entities - Provident
Energy Trust - Taxation of the Trust".
  Nature
of Trust Units
  The Trust
Units do not represent a traditional investment in the oil and natural
gas or NGL processing sectors and should not be viewed by investors as
shares in the Trust or other interests in the Trust's other
entities.  The Trust Units represent a fractional interest in the
Trust.  The Trust Units will not represent a direct investment in
Provident's business.  As holders of Trust Units, Trust 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 price
per Trust Unit is a function of the anticipated Distributable Cash, the oil and
gas properties of Provident, the assets of the Midstream Business and
Provident's ability to affect long-term growth in the value of the
Trust.  The market price of the Trust Units will be sensitive to a
variety of market conditions including, but not limited to, interest rates and
the ability of  Provident to acquire suitable energy related
assets and to fund distributions.  Changes in market conditions
may adversely affect the trading price of the Trust Units.
  The Trust Units are not"deposits"within the meaning of theCanada Deposit
Insurance Corporation Act(Canada) and are not insured under
the provisions of that Act or any other legislation. Furthermore the Trust is
not a trust company and, accordingly, it is not registered under any trust and
loan company legislation as it does not carry on or intend to carry on the
business of a trust company.
  Redemption
Right
  It is
anticipated that the redemption right will not be the primary mechanism for
Trust Unitholders to liquidate their investments.  Notes which may be
distributed in specie to Trust Unitholders in connection with a redemption, will
not be listed on any stock exchange and no established market is expected to
develop for such notes.  Cash redemptions are subject to
limitations.
  
 - 53
-
 
 Unitholder
Limited Liability
  The Trust
Indenture provides that no Trust Unitholder will be subject to any liability in
connection with the Trust or its assets or obligations and, in the event that a
court determines that Trust Unitholders are subject to any such liabilities, the
liabilities will be enforceable only against, and will be satisfied only out of,
the Unitholder's share of the Trust's assets.
  The Trust
Indenture provides that all written instruments signed by or on behalf of the
Trust 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 the Trust 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
operations of Provident 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 Trust Unitholders for claims against the
Trust.
  On July
1, 2004 the Income Trusts
Liability Act (Alberta) came into force.  This Act creates a
statutory limitation on the liability of unitholders of Alberta income trusts
such as the Trust.  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 come into effect.
  Regulatory
Matters
  Provident's
operations are subject to a variety of federal, provincial laws and regulations,
including laws and regulations relating to the protection of the
environment.
  Conflicts
of Interest
  The
directors and officers of PEL 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 PEL 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 shall disclose his interest in such contract or agreement and shall
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.  The business of Provident is subject to
other risks and matters, which are outside of their control.
  Dependence
on Key Personnel
  The
success of the operations of Provident will be largely dependent on the skills
and expertise of key personnel to manage the overall business and, in the
natural gas midstream, NGL processing and marketing business, to achieve
positive margins.  The continued success of Provident will be
dependent on its ability to retain or recruit such personnel.
  Variations
in Interest Rates and Foreign Exchange Rates
  Variations
in interest rates could result in a significant change in the amount Provident
pays to service debt, potentially impacting distributions to
Unitholders.
  Variations
in the exchange rate for the Canadian dollar versus the U.S. dollar could result
in a significant change in the amount Provident receives on the sale of its
production, which may affect future distributions and the future value of
Provident's reserves as determined by independent evaluators.
 Statutory
Remedies
  The Trust
is not a legally recognized entity within the relevant definitions of 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 a restructuring of the
Trust were
  
 - 54
-
 
 necessary,
the Trust would not be able to access the remedies available
thereunder.  In the event of a restructuring, a holder of Debentures
may be in a different position than a holder of unsecured indebtedness of a
corporation.
  INTERESTS
OF MANAGEMENT AND OTHERS IN MATERIAL TRANSACTIONS
  No
director or executive officer of Provident, no person or company that
beneficially owns, or controls or directs, directly or indirectly, more than 10
percent of the outstanding Trust Units and no associate or affiliate of any of
the foregoing persons or companies, has or has had any material interest, direct
or indirect, 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 the Trust, other than as
described in this Annual Information Form.
  TRANSFER
AGENT AND REGISTRAR
  The
transfer agent and registrar for the Trust Units and the debentures is
Computershare Trust Company of Canada at its principal offices in Toronto,
Ontario and Calgary, Alberta.
  INTERESTS
OF EXPERTS
  As of the
date hereof, the designated professionals of McDaniel, independent oil and gas
reservoir engineers, as a group, beneficially own, directly or indirectly, less
than 1 percent of the Trust Units.  As of the date hereof, the
designated professionals of AJM, independent oil and gas reservoir engineers, as
a group, beneficially own, directly or indirectly, less than 1 percent of the
Trust Units.
  MATERIAL
CONTRACTS
  There are
no material contracts entered into by the Trust or its subsidiaries during the
most recently completed financial year or since January 1, 2002 and which
are still in effect, other than contracts entered into in the ordinary course of
business and other than (a) the Trust Indenture described herein under the
heading "Information Concerning the Trust, PEL, PMHLP and Other
Entities"; and (b)  the Canadian Credit Facility described herein under the
heading "Information Concerning the Trust, PEL, PMHLP and Other Entities - Debt
Financing".
  Each of
the Trust Indenture and the Canadian Credit Facility has been filed on SEDAR and
is available under the Trust's issuer profile at www.sedar.com.
  DOCUMENTS
INCORPORATED BY REFERENCE
  Any
statement contained in a document incorporated or deemed to be incorporated by
reference herein shall be deemed to be modified or superseded for the purposes
of this Annual Information Form to the extent that a statement contained herein,
or any other subsequently filed document which also is or is deemed to be
incorporated by reference herein, modifies or supersedes that
statement.  The modifying or superseding statement need not state that
it has modified or superseded a prior statement or include any other information
set forth in the document that is modified or superseded.  The making
of a modifying or superseding statement shall not be deemed an admission for any
purposes that the modified or superseded statement, when made, constituted a
misrepresentation, an untrue statement of a material fact or an omission to
state a material fact that is required to be stated or that is necessary to make
a statement not misleading in light of the circumstances in which it was
made.  Any statement so modified or superseded shall not be deemed,
except as so modified or superseded, to constitute a part of this Annual
Information Form.
  
 - 55
-
 
 The Trust
will provide without charge to each security holder to whom this Annual
Information Form is delivered, upon the written or oral request of such person
(and to each person who is not a security holder of the Trust upon payment of a
reasonable charge), a copy of any or all of the documents incorporated herein by
reference, other than exhibits to such documents (unless such exhibits are
specifically incorporated by reference into such documents).  Requests
for such documents should be directed to the office of Investor Relations,
Provident Energy Ltd., 2100, 250 - 2nd Street
S.W., Calgary, Alberta T2P 0C1, telephone: (403)
231-6710.  Documents incorporated by reference in this Annual
Information Form are also available on SEDAR at www.sedar.com.
  PRINCIPAL
HOLDERS OF TRUST UNITS
  As at the
date hereof, to the knowledge of Provident, no person or company owned of record
or beneficially, directly or indirectly, more than 10 percent of the issued and
outstanding Trust Units.  As at March 19,
2009,the
directorsand senior officers of Provident, as a group, beneficially
owned, directly or indirectly, 2.4 million Trust Units or approximately 1.0
percentof the
issued and outstanding Trust Units.
  ADDITIONAL
INFORMATION
  Additional
information related to the remuneration of the directors and officers
of PEL for the year ended December 31, 2008, the indebtedness of the
directors and officers of PEL, the principal holders of Trust Units and
securities authorized for issuance under equity compensation plans, where
applicable, is contained in the Management Proxy Statement and Information
Circular of the Trust for its most recent annual meeting of Unitholders that
involved the election of directors.  Additional financial information
is provided in the Trust's audited consolidated financial statements and
management's discussion and analysis for the year ended December 31,
2008.
  Additional
copies of this Annual Information Form are available on SEDAR at www.sedar.com
or may be obtained from Provident.  Please contact:
   Lynn
Rannelli, Assistant Corporate Secretary
 Provident
Energy Ltd.
 2100, 250
– 2nd Street
S.W.
 Calgary,
Alberta  T2P 0C1
  Telephone:          (403)
296-2233
 Fax:                      (403)
294-0111
 
 Additional
information relating to the Trust may be found on SEDAR at
www.sedar.com.
 
 - 56
-
 
 SCHEDULE
A
  
  Audit Committee Terms of
Reference
  Provident
Energy Trust (the "Trust") has delegated a number of duties and responsibilities
regarding the management and administration of the operations and affairs of the
Trust to its subsidiary, Provident Energy Ltd. (the "Corporation") pursuant to
the trust indenture, as amended.  As such, the board of directors (the
"Board") of the Corporation has oversight responsibilities, authorities and
duties in connection with the business of the Trust and the
Corporation.  The Board has delegated the specific oversight
responsibilities, authorities and duties as described below to the Audit
Committee (the "Committee").
  For the
purpose of these terms of reference, the term "Provident" shall include the
Trust, the Corporation and their subsidiaries.
  Composition
  The
Committee will consist of three or more directors as determined by the
Board.  The members of the Committee shall be appointed by the
Board.  The Governance, Human Resources and Compensation Committee of
the Board shall recommend to the Board eligible directors to fill vacancies on
the Committee.  Each member shall serve until his or her successor is
appointed, unless he shall resign or be removed by the Board or he shall
otherwise cease to be a director of the Corporation.  The Board shall
fill any vacancy if the membership of the Committee is less than three
directors.  The Chair of the Committee may be designated by the Board
or, if it does not do so, the members of the Committee may elect a Chair by vote
of a majority of the full Committee membership.
  All
members of the Committee must satisfy the independence, financial literacy and
experience requirements of applicable Canadian and United States securities
laws, rules and guidelines, any applicable stock exchange requirements or
guidelines and any other applicable regulatory rules.  In particular:
(i) each member shall be "independent" and "financially literate" within
the meaning of National Instrument 52-110 - Audit Committees,
(ii) each member shall be "independent" and "financially literate" within
the meaning of the rules of the New York Stock Exchange, and (iii) at least
one member must be an "audit committee financial expert" within the meaning of
that term under the United States Securities Exchange Act of
1934, as amended, and the rules adopted by the United States Securities
and Exchange Commission thereunder (collectively, the "U.S.
Rules").
  Members
of the Committee may not, other than in their respective capacities as members
of the Committee, the Board or any other committee of the Board, accept directly
or indirectly any consulting, advisory or other compensatory fee from Provident,
or be an "affiliated person" (as such term is defined in the U.S. Rules) of
Provident.  For greater certainty, director's fees, options and
similar compensation arrangements and fixed amounts of compensation under a
retirement plan (including deferred compensation) for prior service with
Provident that are not contingent on continued service should be the only
compensation a Committee member receives from Provident.
  
 
 
 Communication,
Authority to Engage Advisors and Expenses
  The
Committee shall have access to such officers and employees of the Provident, the
external auditor, the independent reserves evaluator(s) and to such other
information respecting Provident, as it considers to be necessary or advisable
in order to perform its duties and responsibilities.
  The
Committee provides an avenue for communication, particularly for outside
directors, with the external auditor and financial and senior management and the
Board.  The external auditor shall have a direct line of communication
to the Committee through its Chair and shall report directly to the
Committee.  The Committee, through its Chair, may directly contact any
employee of Provident as it deems necessary, and any employee may bring before
the Committee, on a confidential basis, any matter involving Provident's
financial practices or transactions.
  The
Committee has the authority to engage independent counsel and other advisors as
it determines necessary to carry out its duties and to set the compensation for
any such counsel and advisors.  Any engagement of independent counsel
or other advisors is to be at Provident's expense.
  Provident
shall be responsible for all expenses of the Committee that are deemed necessary
or appropriate by the Committee in carrying out its duties including the
compensation of the external auditor for issuing an audit report or performing
other audit, review or attest services.
  Meetings
and Record Keeping
  Meetings
of the Committee shall be conducted as follows:
  1.
              the
      Committee shall meet at least quarterly at such times and at such
      locations as the Chair of the Committee shall determine, provided that
      meetings shall be scheduled so as to permit timely review of the Trust's
      quarterly and annual financial statements and related management's
      discussion and analysis and earnings press releases.  The
      external auditor or any two members of the Committee may also request a
      meeting of the Committee.  The Committee shall also meet
      separately with the external auditor and/or internal auditor periodically
      as the Committee may deem appropriate.  The Chair of the
      Committee shall hold in camera sessions of the Committee, without
      management present, at every
meeting;
  2.
              the
      Chair of the Committee shall preside as chair at each Committee meeting
      and lead Committee discussion on meeting agenda
  items;
  3.
              the
      quorum for meetings shall be a majority of the members of the Committee,
      present in person or by telephone or by other telecommunication device
      that permits all persons participating in the meeting to hear each
      other;
  4.
              if
      the Chair of the Committee is not present at any meeting of the Committee,
      one of the other members of the Committee who is present at the meeting
      shall be chosen by the Committee to preside at the
  meeting;
  5.
              the
      Chair shall, in consultation with management and the external auditor,
      establish the agenda for the meetings and instruct management to ensure
      that properly prepared agenda materials are circulated to the Committee
      with sufficient time for study prior to the
  meeting;
  6.
              every
      question at a Committee meeting shall be decided by a majority of the
      votes cast;
  
 A
-2
 
 7.
              a
      Committee member, or any other person selected by the Committee, shall be
      appointed at each meeting to act as secretary for the purpose of recording
      the minutes of each meeting.
  8.
              the
      Chief Executive Officer (the "CEO"), the President and the Chief Financial
      Officer ("CFO") shall be available to advise the Committee, shall receive
      notice of meetings and may attend meetings of the Committee at the
      invitation of the Chair of the Committee.  Other management
      representatives, other Board members, officers or employees of Provident,
      the external auditor, outside counsel and other experts or consultants may
      be invited to attend as necessary;
and
  The
Committee shall provide the Board with a summary of all meetings together with a
copy of the minutes from such meetings.  Where minutes have not yet
been prepared, the Chair shall provide the Board with oral reports on the
activities of the Committee.  Information reviewed and discussed by
the Committee at any meeting shall be referred to in the minutes and made
available for examination by the Board upon request to the Chair of the
Committee.
  Responsibilities
  The
Committee is part of the Board.  Its primary functions are to assist
the Board in fulfilling its oversight responsibilities with respect to: (i) the
integrity of the Trust's Financial Statements, including the review and
recommendation for approval of the financial statements and the financial
reporting of the Trust; (ii) the assessment of the system of internal,
accounting and financial reporting controls and procedures that management has
established, including for the purpose of monitoring its compliance with
regulatory requirements; and (iii) the appointment, compensation and evaluation
of the external auditor and the oversight of the external audit process,
including the external auditor's performance, qualifications and
independence.  In addition, the Committee shall assist the Board as
requested in fulfilling its oversight responsibilities with respect to: (i)
financial policies and strategies; (ii) financial risk management practices; and
(iii) transactions or circumstances which could materially affect the financial
profile of the Trust.
  Management
is responsible for establishing and maintaining controls, procedures and
processes and the Committee is appointed by the Board to oversee, review and
monitor those controls, procedures and processes.
  The
Committee, in its capacity as a committee of the Board and subject to the rights
of unitholders and applicable law, shall be directly responsible for overseeing
the relationship of the external auditor with the Trust, including the
appointment, compensation, retention and oversight of the work of any external
auditor engaged (including resolution of disagreements between management of
Provident and the external auditor regarding financial reporting) for the
purpose of preparing or issuing an audit report or performing other audit,
review or attest services for the Trust.  The external auditor shall
report directly to the Committee.  The Committee should have a clear
understanding with the external auditor that such external auditor must maintain
an open and transparent relationship with the Committee, and that the ultimate
accountability of the external auditor is to the unitholders of the
Trust.
  Specific
Duties
  In
carrying out its role, the Committee has the following specific authorities and
responsibilities:
  1.
              Financial
      Information and Reporting
  
 A
-3
  (a)
                to
      review with management and the external auditor, and recommend to the
      Board for approval, the annual and interim financial statements of the
      Trust and related financial reporting, including management's discussion
      and analysis and earnings press
releases;
 (b)
              to
      review and discuss with management the type and presentation of
      information to be included in press releases which contain financial
      information taken from Provident's financial statements prior to the
      release of such press release to the public, paying particular attention
      to any use of information which is not prepared in accordance with
      Canadian generally accepted accounting principles ("GAAP"), such as "pro
      forma" or "adjusted" non-GAAP information, as well as financial
      information and earnings guidance provided by Provident to analysts and
      rating agencies;
  (c)
              to
      review with management and recommend to the Board for approval, any
      financial statements of the Trust which have not previously been approved
      by the Board and which are to be included in a prospectus or other public
      disclosure document of the Trust;
  (d)
              to
      consider and be satisfied that adequate policies and procedures are in
      place for the review of the Trust's disclosure of financial information
      extracted or derived from the Trust's financial statements (other than
      disclosure referred to in clause (1)(a) above), and periodically assess
      the adequacy of such procedures;
  (e)
              to
      review major issues regarding accounting principles and financial
      statement presentations, including any significant changes in Provident's
      selection or application of accounting
  principles;
  (f)
              to
      review analyses prepared by management and/or the external auditor setting
      forth any significant financial reporting issues and judgments made in
      connection with the preparation of Provident's financial statements,
      including analyses of the effects of alternative GAAP methods on the
      financial statements;
  (g)
              to
      review the effect of regulatory and accounting initiatives, as well as
      off-balance sheet structures, on Provident's financial
      statements;
  2.
              Internal
      Controls
  (a)
              to
      review the internal control staff functions
  including:
  (i)
              the
      purpose, authority and organizational reporting lines,
  and
  (ii)
              the
      annual audit plan, budget and staffing
thereof;
  (b)
              to
      review, with the CFO, controller or others, as appropriate, Provident's
      internal system of audit controls and the results of internal
      audits;
  (c)
              to
      review major issues regarding the adequacy of Provident's internal
      controls and any special audit steps adopted in light of material control
      deficiencies;
  (d)
              to
      establish procedures for:
  (i)
              the
      receipt, retention and treatment of any complaint regarding accounting,
      internal accounting controls or auditing matters, and
  
 A
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 (ii)
              the
      confidential, anonymous submissions by employees of concerns regarding
      questionable accounting or auditing
matters;
  3.
              External
      Audit
  (a)
              to
      recommend to the Board the external auditor to be nominated for the
      purpose of preparing or issuing an auditor's report or performing other
      audit, review or attest services and the compensation of such
      auditor;
  (b)
              to
      evaluate and oversee the services provided by the external auditor and
      recommend to the Board, if necessary, the replacement of the external
      auditor;
  (c)
  (i)
              to
      pre-approve or approve (if pre-approval is not required by law) the
      services related to, any audit service or non-prohibited non-audit service
      and, if desired, establish detailed policies and procedures for the
      pre-approval of audit services and non-prohibited non-audit services by an
      external auditor.  The Committee may delegate this ability to
      one or more members of the Committee to the extent permitted by applicable
      law, provided that any pre-approvals granted pursuant to such delegation
      must be detailed as to the particular service to be provided, may not
      delegate Committee responsibilities to management of Provident and must be
      reported to the full Committee at its next scheduled meeting,
      or
  
 (ii)
              adopt
      specific policies and procedures for the engagement of the external
      auditor for the purposes of the provision of non-audit
      services;
  (d)
              to
      obtain and review at least annually a written report by the external
      auditor setting out the auditor's internal quality control procedures, any
      material issues raised by the auditor's internal quality control reviews,
      or by inquiry or investigation by governmental or professional authorities
      within the preceding five years, respecting one or more independent audits
      carried out by the firm and the steps taken to resolve those
      issues;
  (e)
              to
      review and discuss with the external auditor all relationships that the
      external auditor and its affiliates have with Provident in order to
      determine the external auditor's independence, including, without
      limitation:
  (i)
              requesting,
      receiving and reviewing, on a periodic basis but at least annually, a
      formal written statement from the external auditor delineating all
      relationships that may reasonably be thought to bear on the independence
      of the external auditor with respect to
  Provident,
  (ii)
              discussing
      with the external auditor any disclosed relationships or services that the
      external auditor believes may affect the objectivity and independence of
      the external auditor, and
  (iii)
              recommending
      that the Board take appropriate action in response to the external
      auditor's report to satisfy itself of the external auditor's independence
      at least annually, obtain and review a report by the external auditor
      describing: the firm's internal quality control procedures; any material
      issues raised by the most recent
  
 A
-5
 
 internal
      quality control review, or peer review, of the firm, 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 a firm, and any steps taken to deal with any such
      issues;
  (f)
              to
      review the audit plan of the external auditor prior to the commencement of
      the audit;
  (g)
              to
      set clear hiring policies for Provident regarding partners and employees
      and former partners and employees of the present and former external
      auditor of the Trust;
  (h)
              to
      obtain assurance from the external auditor 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 of
      any illegal acts by the external
auditor;
  (i)
              to
      review with the external auditor any audit problems or difficulties,
      including any restrictions on the scope of the external auditor's
      activities or on access to requested information, any significant
      disagreements with management, and management's response (such review
      should also include discussion of the responsibilities, budget and
      staffing of Provident's internal audit function, if
  any);
  (j)
              to
      review and discuss a report from the external auditor at least quarterly
      regarding:
  (i)
              all
      critical accounting policies and practices to be
  used,
  (ii)
              all
      alternative treatments within generally accepted accounting principles for
      policies and practices related to material items that have been discussed
      with management, including the ramifications of the use of such
      alternative disclosures and treatments, and the treatment preferred by the
      external auditor,
  (iii)
              other
      material written communications between the external auditor and
      management, such as any management letter or schedule of unadjusted
      differences, and
  (iv)
              to
      present its conclusions with respect to the external auditor to the full
      Board;
  (k)
              the
      Committee will ensure the rotation of partners on the audit engagement
      team of the external auditor in accordance with applicable
      law.  The Committee will also periodically consider whether, in
      order to assure continuing external auditor independence, it is
      appropriate to adopt a policy of rotating the external auditing firm on a
      regular basis;
  (l)
              the
      Committee will review and evaluate the lead partner of the external
      auditor;
  4.
              Risk
      Management
  (a)
              to
      review and monitor Provident's major financial risks and risk management
      policies and the steps taken by management to  monitor and
      control those risks;
  (b)
              at
      the request of the Board, review transactions or matters which could
      materially affect the financial profile of the
  Trust;
  
 A
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 (c)
              the
      Committee shall, at least annually, provide a review of the Corporation's
      directors and officers liability insurance to the
  board.
  5.
              Compliance
      and Review of CEO and CFO Certification
Process
  (a)
              to
      review Provident's financial reporting procedures and policies to ensure
      compliance with all legal and regulatory requirements and to investigate
      any non-adherence to those procedures and policies;
  and
  (b)
              in
      connection with its review of the annual audited financial statements and
      interim financial statements, the Committee will also review the process
      for the CEO and CFO certifications with respect to the financial
      statements and Provident's disclosure and internal controls, including any
      material deficiencies or changes in those controls.  The
      Committee will review with the CEO, the CFO and the external auditor: (i)
      all significant deficiencies and material weaknesses in the design or
      operation of Provident's internal control over financial reporting which
      could adversely affect Provident's ability to record, process, summarize
      and report financial information required to be disclosed by the Trust in
      the reports that it files or submits under the United States Securities
      Exchange Act of 1934, as amended, within the required time periods, and
      (ii) any fraud, whether or not material, that involves management of
      Provident or other employees who have a significant role in Provident's
      internal control over financial
reporting.
  Other
Matters
  1.
              The
      Committee shall review and reassess the adequacy of this mandate at least
      annually and otherwise as it deems appropriate and recommend changes to
      the Board.
  2.
              The
      performance of the Committee shall be evaluated annually by the Board
      against criteria defined in the Committee and Board
    mandates.
  3.
              The
      Committee may, at the request of the Board or on its own initiative,
      investigate such other matters as it considers necessary or appropriate in
      the circumstances, including, without limitation, matters relating to
      corporate governance, compensation and director
    nominations.
  4.
              The
      Committee may delegate its responsibilities to sub-committees of the
      Committee.
  
 A
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 APPENDIX
A
  AUDIT
COMMITTEE ANNUAL CALENDAR
 (December
31 year end)
  Quarterly
Audit Committee Meetings: May, August and November
  ·
                Approval
      of quarterly financial statements such
as:
 MD&A;
 press
release;
 estimates
and management judgments; and
 Review of
report from external auditor.
  ·
                Management
      certification process with report from CEO/CFO and processes
      followed.
   ·
                Other
      standard items including management reporting
  on:
 Material
communication with rating agencies;
 Material
legal matters/litigation; and
 Analyst
reports.
  ·
                Report
      from Audit Committee Chair on pre-approvals for audit, non-audit, review
      or attestation assignments.
  ·
                In camera review with
      external auditor.
  February
or March Meeting to Review Audited Financial Statements
  ·
                Review
      annual financial statements, MD&A and related
    disclosure.
  ·
                Discuss
      significant accounting
policies.
  ·
                Discuss
      critical estimates, and judgments and impact on
  statements.
  ·
                Review
      business risks disclosure in
MD&A.
  ·
                Receive
      external auditor's report on statutory audit and various matters where
      external auditor is required to report, such
as:
 auditor
      independence;
 methods
      used to account for significant unusual
  transactions;
 material
      proposed audit adjustments and immaterial adjustments not recorded by
                management;
 auditor
      judgments about the quality of the Company's accounting
      principles;
 management-related
      issues encountered in performing the audit;
and
 disagreements
      with management over the application of accounting principles,
                management's accounting estimates and related
  matters.
  ·
              Review
      management's "internal control report" to be included in annual report and
      external auditor's assessment of
same.
  ·
              Internal
      control issues, if any.
  ·
              Separate
      in camera
      meetings with the external auditor and external
  counsel.
  ·
              Annual
      information form and comparable
40-F.
  A
-8
 ·
              Public
      disclosure relevant to Audit Committee, such as re-appointment of auditor,
      disclosure of pre-approval procedures as required by SEC Auditor
      Independence Rules and disclosure relating to financial
      experts.
  October/November
Meeting
  ·
              Discuss
      annual audit plan including scope of engagement and related matters such
      as:
 audit
team and potential rotation;
 review
and consideration of budgeted audit fees; and
 special
areas for concentration by external audit.
  ·
              Review
      preparations for production of "internal control report" for annual
      report.
  ·
              Review
      Audit Committee charter and report to
Board.
  ·
              Review
      and affirmation of principles for pre-approval of audit, non-audit, review
      and attestation services.
  Special
issues to be dealt with at one or more regular meetings or through a special
meeting of the Audit Committee
  ·           Educational
component to Audit Committee functions such as:
  critical
accounting policies/estimates/general discussion;
  treasury
activities;
  internal
control risks;
  support
to CEO/CFO certification;
  financing
vehicles, loan documents and applicable covenant patterns;
  taxation
issues and tax planning;
  new
developments such as:
 -
non-GAAP earnings measures; and
 -
identification of financial experts;
  competitors
and accounting issues involving competitors;
  preparing
of Audit Committee effectiveness report for Board of Directors;
  business
risks and related oversight responsibilities of Audit Committee including
applicable procedures; and
  earnings
guides such as:
 - pro
forma reporting; and
 -
selective disclosure policy.
  ·
              Review
      and consideration of succession planning and related issues with respect
      to Audit Committee Chair and Audit Committee members in light of
      independence requirements and financial expertise
      requirements.
  ·
              Communication
      with the Corporate Governance Committee as may be
  required.
  ·
              Review
      of complaints received and outcome of
  investigation.
  ·
                These
      educational elements may be dealt with at a special annual meeting of the
      Committee.
  
   A
-9
 
  Management’s
Discussion & Analysis
 
 
 The
following analysis provides a detailed explanation of Provident’s operating
results for the quarter and year ended December 31, 2008 compared to the quarter
and year ended December 31, 2007 and should be read in conjunction with the
consolidated financial statements of Provident. This analysis has been prepared
using information available up to March 11, 2009.
 
 Provident
Energy Trust has diversified investments in certain segments of the energy value
chain. Provident currently operates in two key business segments: Canadian crude
oil and natural gas production (“COGP” or “Provident Upstream”), and Provident
Midstream.  Provident’s Upstream business produces crude oil and
natural gas from seven core areas in the western Canadian sedimentary
basin.  The Midstream business unit operates in Canada and the U.S.A.
and extracts, processes, markets, transports and offers storage of natural gas
liquids within the integrated facilities at Younger in British Columbia,
Redwater and Empress in Alberta, Kerrobert in Saskatchewan, Sarnia in Ontario,
Superior in Wisconsin and Lynchburg in Virginia.  Effective in the
first quarter of 2008, Provident’s United States oil and natural gas production
(“USOGP”) business was accounted for as discontinued operations and comparative
figures have been reclassified to conform with this presentation (see note 15 to
the consolidated financial statements).  The USOGP business was sold
in two transactions, the first in June and the second in August,
2008.
 
 The Trust
has applied the proceeds, net of tax, on the sale of the USOGP business to
reduce long-term debt, resulting in a ratio of net debt to total book value
capitalization as at December 31, 2008 of 31 percent compared to 40 percent at
December 31, 2007 (see “Liquidity and capital resources”).
 
 This
analysis commences with a summary of the consolidated financial and operating
results followed by segmented reporting on the Provident Upstream business unit
and the Provident Midstream business unit.  The reporting focuses on
the financial and operating measurements management uses in making business
decisions and evaluating performance.
 
 This
analysis contains forward-looking information and statements.  See
“Forward-looking statements” at the end of the analysis for further
discussion.
  
 
 Provident
Energy 2008 Management’s Discussion and Analysis
 - 1
-
 
 Fourth quarter
highlights
 
 The
fourth quarter highlights section provides commentary on the fourth quarter of
2008 results compared to the fourth quarter of
2007.   Definitions of terms used in this section, as
appropriate, are defined in the year over year section of the Management’s
Discussion and Analysis following later in this press release.
 
 Consolidated
funds flow from operations and cash distributions
  Consolidated
                
                Three
      months ended December 31,($
      000s, except per unit data)
                
                2008
                
                
                2007
                
                
                %
      ChangeFunds
      Flow from Operations and DistributionsFunds
      flow from continuing operations
                
                $
                81,779
                
                
                $
                135,776
                
                
                
                (40
                )Funds
      flow from discontinued operations(1)
                
                
                -
                
                
                
                41,787
                
                
                
                (100
                )Total
      funds flow from operations
                
                $
                81,779
                
                
                $
                177,563
                
                
                
                (54
                )Per
      weighted average unit - basic and diluted (2)
                
                $
                0.32
                
                
                $
                0.72
                
                
                
                (56
                )Declared
      distributions
                
                $
                77,324
                
                
                $
                89,063
                
                
                
                (13
                )Per
      Unit
                
                $
                0.30
                
                
                $
                0.36
                
                
                
                (17
                )Percent
      of funds flow from operations distributed(3)
                
                
                95
                %
                
                
                57
                %
                
                
                67(1)Prior to the sale of
      USOGP, Provident owned approximately 22 per cent of the MLP and 96 per
      cent of BreitBurn.
                  In accordance with generally accepted accounting principles (GAAP) in
      Canada and the United States, these investments were
                  consolidated into Provident's results.(2)Includes dilutive impact of unit options and convertible
      debentures.(3)
      Calculated as declared distributions to unitholders divided by funds flow
      from operations less distributions to non-controlling
                  interests of nil for the quarter (2007 - $22.1 million).
 
 Fourth
quarter 2008 funds flow from continuing operations was $81.8 million, 40 percent
below the $135.8 million recorded in the fourth quarter of
2007.  Provident Upstream’s 2008 fourth quarter funds flow from
operations was $47.2 million, a 20 percent decrease from the $58.7 million
recorded in the comparable 2007 quarter.  The drivers for the decrease
were a nine percent decrease in commodity prices, a four percent decrease in
production volumes and a 25 percent increase in production
costs.  Production volumes and costs were impacted by unscheduled
turnarounds and additional maintenance related to cold weather.  The
reduction in funds flow was partially mitigated by the risk management program,
which generated realized gains of $8.2 million in the fourth quarter of 2008,
compared to $0.5 million in the comparable quarter of 2007.
 
 The
Provident Midstream business unit added $34.6 million to fourth quarter 2008
funds flow from operations, 55 percent below the $77.1 million recorded in the
comparable 2007 quarter. This decrease reflects lower operating margins within
the Midstream segment.  A sharp drop in NGL sales prices driven by the
decrease in crude oil price combined with higher value natural gas-based
inventory had a negative impact on operating margins in the fourth quarter. This
has been partially mitigated by the risk management program generating gains of
$16.1 million in the fourth quarter of 2008 compared to a loss of $38.6 million
in the comparable quarter in 2007.
 
 Funds
flow from operations in USOGP was nil compared to $41.8 million in the
comparable 2007 quarter.  The USOGP operations were sold prior to the
fourth quarter of 2008.
 
 Declared
distributions in the fourth quarter of 2008 totaled $77.3 million, 95 percent of
funds flow from operations. This compares to $89.1 million of declared
distributions in fourth quarter of 2007, 57 percent of funds flow from
operations, after distributions to non-controlling interests of $22.1
million.
 
 
 Provident
Energy 2008 Management’s Discussion and Analysis
 - 2
-
 
 Net
(loss) income
  Consolidated
                Three
      months ended December 31,($
      000s, except per unit data)
                
                2008
                
                
                2007
                
                
                %
      ChangeNet
      (loss) income
                
                $
                (43,248
                )
                
                $
                68,545
                
                
                
                -Per
      weighted average unit
                  –
      basic (1)and diluted(2)
                
                $
                (0.17
                )
                
                $
                0.28
                
                
                
                -(1)
      Based on weighted average number of trust units
    outstanding.(2)Based on weighted average number of trust units outstanding
      including the dilutive impact of the unit option plan and
                  convertible
      debentures.
 
 In the
fourth quarter of 2008, Provident recorded a loss of $43.2 million compared to
net income of $68.5 million in the comparable 2007 quarter.  The
fourth quarter of 2008 included a non-cash goodwill impairment charge of $416.9
million (see “Goodwill” in the annual section of this analysis) that was largely
offset by $404.0 million of unrealized gains on financial derivative
instruments.  The fourth quarter of 2007 included a $179.1 million
unrealized loss on financial derivative instruments and a $161.7 million
dilution gain in discontinued operations related to Provident’s change in
ownership of the MLP.  The preceding, combined with lower fourth
quarter 2008 earnings before interest, taxes, depletion, depreciation, accretion
and other non-cash items (EBITDA) from continuing operations accounts for the
pre-tax swing in net (loss) income from the comparable quarter in
2007.  Future income tax expense in the fourth quarter of 2008 was
largely driven by the tax effect of the unrealized gain on financial derivative
instruments.  The goodwill impairment charge does not result in any
corresponding future income tax recovery.  Future income tax expense
in the fourth quarter of 2008 was $52.4 million compared to a recovery of $71.8
million in the fourth quarter of 2007.
 
 The
Provident Upstream business segment had a net loss of $421.5 million, in the
fourth quarter of 2008 compared to a 2007 fourth quarter net income of $16.9
million.  The majority of the 2008 fourth quarter net loss was due to
a non-cash goodwill impairment charge of $416.9 million.  This,
combined with a 21 percent decrease in EBITDA and a $44.4 million increase in
future income taxes, partially offset by a $ 43.5 million increase in unrealized
gains on financial derivative instruments accounts for the quarter over quarter
change.
 
 The
Provident Midstream segment had net income of $359.2 million in the fourth
quarter of 2008, compared to a net loss of $62.0 million in the fourth quarter
of 2007.  The increase was driven by a $377.7 million unrealized gain
on financial derivative instruments in the fourth quarter of 2008 compared to a
loss of $161.8 million in 2007.  This increase to net income was
partially offset by a $51.7 million decrease in Midstream EBITDA as well as a
future income tax expense of $52.8 million in 2008 compared to a recovery in
2007 of $27.0 million.
 
 Net
income from discontinued operations (USOGP) was $19.1 million in the fourth
quarter of 2008 with a comparative net income of $113.6 million for
2007.  USOGP was sold in the second and third quarters of
2008.  The fourth quarter 2008 results represent an adjustment to the
provision for income taxes related to the sale.  Net income from
discontinued operations in the fourth quarter of 2007 was primarily driven by a
$161.7 million dilution gain related to Provident’s change in ownership of the
MLP.
 
 Provident’s
net income figures are affected by the requirement to “mark-to-market” all
financial derivative instruments at the end of the period and report these
unrealized gains or losses as part of current period net
income.  Because Provident’s commodity price risk management program
extends up to five years into the future in the Midstream segment, net earnings
can show substantial quarterly variation that is not necessarily related to
current operations.
 
 Reconciliation
of non-GAAP measures
 
 The Trust
calculates earnings before interest, taxes, depletion, depreciation, accretion
and other non-cash items (EBITDA) within its segment disclosure. EBITDA is a
non-GAAP measure.  A reconciliation between EBITDA and loss from
continuing operations before taxes follows:
  
 Provident
Energy 2008 Management’s Discussion and Analysis
 - 3
-
  
 Three
      months ended December 31,($
      000s)
                
                2008
                
                
                2007
                
                
                %
      ChangeEBITDA
                
                $
                87,423
                
                
                $
                152,432
                
                
                
                (43
                )Adjusted
      for:Cash
      interest
                
                
                (9,998
                )
                
                
                (16,008
                )
                
                
                (38
                )Unrealized
      gain (loss) on financial derivative instruments
                
                
                404,023
                
                
                
                (179,061
                )
                
                
                -Goodwill
      impairment
                
                
                (416,890
                )
                
                
                -
                
                
                
                -Depletion,
      depreciation and accretion and other non-cash expenses
                
                
                (78,438
                )
                
                
                (73,757
                )
                
                
                6Loss
      from continuing operations before taxes
                
                $
                (13,880
                )
                
                $
                (116,394
                )
                
                
                (88
                )
  The
following table reconciles funds flow from operations with cash provided by
operating activities and distributions to unitholders:
  Reconciliation
      of funds flow from operations to distributions
                
                Three
      months ended December 31,($
      000s, except per unit data)
                
                2008
                
                
                2007
                
                
                %
      ChangeCash
      provided by operating activities
                
                $
                150,032
                
                
                $
                137,330
                
                
                
                9Change
      in non-cash operating working capital
                
                
                (70,677
                )
                
                
                38,511
                
                
                
                -Site
      restoration expenditures
                
                
                2,424
                
                
                
                1,722
                
                
                
                41Funds
      flow from operations
                
                
                81,779
                
                
                
                177,563
                
                
                
                (54
                )Distributions
      to non-controlling interests
                
                
                -
                
                
                
                (22,124
                )
                
                
                (100
                )Cash
      retained for financing and investing activities
                
                
                (4,455
                )
                
                
                (66,376
                )
                
                
                (93
                )Distributions
      to unitholders
                
                
                77,324
                
                
                
                89,063
                
                
                
                (13
                )Accumulated
      cash distributions, beginning of period
                
                
                1,535,144
                
                
                
                1,171,114
                
                
                
                31Accumulated
      cash distributions, end of period
                
                $
                1,612,468
                
                
                $
                1,260,177
                
                
                
                28Cash
      distributions per unit
                
                $
                0.30
                
                
                $
                0.36
                
                
                
                (17
                )
  Taxes
 Three
      months ended December 31,($
      000s)
                
                2008
                
                
                2007
                
                
                %
      ChangeCapital
      tax expense
                
                $
                485
                
                
                $
                510
                
                
                
                (5
                )Current
      and withholding tax recovery
                
                
                (4,453
                )
                
                
                (5
                )
                
                
                88,960Future
      income tax expense (recovery)
                
                
                52,379
                
                
                
                (71,815
                )
                
                
                -$
                48,411
                
                
                $
                (71,310
                )
                
                
                -
  Fourth
quarter Saskatchewan capital taxes totaled $0.5 million, consistent with the
$0.5 million recorded in the fourth quarter of 2007.
 
 The
current and withholding tax recovery was $4.5 million in the fourth quarter of
2008.  These recoveries arise from Provident’s Midstream operations
and are the result of lower fourth quarter income subject to tax.
 
 The 2008
fourth quarter future tax expense of $52.4 million compares to a recovery of
$71.8 million in the fourth quarter of 2007.  The future tax expense
in the fourth quarter of 2008 resulted primarily from future taxes calculated on
the unrealized gains on financial derivative instruments while the goodwill
impairment charge is not tax effected.  The future income tax recovery
in the quarter of 2007 was largely related to the unrealized loss on financial
derivative instruments.
 
 Provident
Energy 2008 Management’s Discussion and Analysis
 - 4
-
 
 Interest
expense
  Continuing
      operations
                
                Three
      months ended December 31,($
      000s, except as noted)
                
                2008
                
                
                2007
                
                
                %
      ChangeInterest
      on bank debt
                
                $
                5,015
                
                
                $
                13,121
                
                
                
                (62
                )Interest
      on convertible debentures
                
                
                4,983
                
                
                
                4,986
                
                
                
                -Discontinued
      operations portion
                
                
                -
                
                
                
                (2,099
                )
                
                
                (100
                )Total
      cash interest
                
                $
                9,998
                
                
                $
                16,008
                
                
                
                (38
                )Weighted
      average interest rate on all long-term debt
                
                
                5.1
                %
                
                
                5.9
                %
                
                
                (14
                )Debenture
      accretion and other non-cash interest expense
                
                
                1,465
                
                
                
                1,173
                
                
                
                25Total
      interest expense
                
                $
                11,463
                
                
                $
                17,181
                
                
                
                (33
                )
  Interest
expense decreased for the quarter as compared to the same quarter in 2007 due to
significantly lower debt levels and lower market interest rates.  Cash
proceeds on the sale of USOGP in June and August of 2008, amounting to $457.9
million, net of tax, were used to pay down debt.
 
 Commodity
price risk management program
 
 In the
fourth quarter of 2008, when commodity prices dropped dramatically, the Program
assisted with stabilizing cash flow by contributing $24.3 million, or 30 percent
of fourth quarter funds flow from operations.
 
 A summary
of Provident’s risk management contracts executed during the fourth quarter of
2008 is contained in the following tables.
 
 Activity
in the Fourth Quarter:
  Provident
      MidstreamYear
                Product
                Volume
                  (Buy)/Sell
                
                Terms
                Effective
      Period2009
                Crude
      Oil
                (140)
      Bpd
                
                US
      $65.04 per bbl (8)
                January
      1 - March 31(1,052)
      Bpd
                
                Cdn
      $70.21 per bbl (11)
                January
      1 - November 30323
      Bpd
                
                US
      $57.78 per bbl (9)
                May
      1 - May 312,000
      Bpd
                
                US
      $69.73 per bbl (10)
                January
      1 - December 31Natural
      Gas
                2,500
      Gjpd
                
                Cdn
      $6.56 per gj (9)
                January
      1 - January 31Propane
                200
      Bpd
                
                US
      $0.94 per gallon (4)
      (8)
                January
      1 - March 31333
      Bpd
                
                US
      $0.99 per gallon (5)
      (9)
                January
      1 - March 31333
      Bpd
                
                US
      $0.95 per gallon (4)
      (9)
                January
      1 - March 31Natural
      Gasoline
                (2,000)
      Bpd
                
                US
      $1.36 per gallon (10)
                January
      1 - December 31Normal
      Butane
                (1,473)
      Bpd
                
                US
      $0.76 per gallon (10)
                April
      1 - December 312010
                Normal
      Butane
                (1,500)
      Bpd
                
                US
      $0.76 per gallon (10)
                January
      1 - March 31(1)The
      above table represents a number of transactions entered into over the
      fourth quarter 2008.(2)Natural
      gas contracts are settled agains AECO monthly index.(3)Crude
      Oil contracts are settled against NYMEX WTI calendar
    average.(4)Propane
      contracts are settled against Belvieu C3 TET.(5)Propane
      contracts are settled against Conway In-Well C3.(6)Normal
      Butane contracts are settled against Belvieu NC4 TET.(7)Natural
      Gasoline contracts are settled against Belevieu NON-TET Natural
      Gasoline.(8)Conversion
      of Crude Oil BTU contracts to liquids.(9)Midstream
      inventory price stabilization contracts.(10)Midstream
      margin contracts.(11)BTU re-balancing of Crude Oil contracts.
   Provident
Energy 2008 Management’s Discussion and Analysis
 - 5
-
 
 Settlement
of commodity contracts
  The
following is a summary of the net cash flow to settle commodity contracts during
the fourth quarter of 2008.  For comparative purposes, the 2007
amounts are also summarized.
 
 i)  Provident
Upstream
 
 a)  Crude
Oil
 
 For the
quarter ending December 31, 2008, Provident received $6.1 million (2007 – paid
$4.6 million) to  settle various oil market based contracts on an
aggregate volume of 0.4 million barrels (2007 – 0.6 million
barrels).
 
 b)  Natural
Gas
 
 For the
quarter ending December 31, 2008, Provident received $2.1 million (2007 - $5.1
million) to settle various natural gas market based contracts on an aggregate
volume of 1.9 million gj’s (2007 – 4.5 million gj’s).
 
 ii)  Provident
Midstream
 
 For the
quarter ending December 31, 2008 Provident paid $4.0 million (2007 – received
$0.2 million) to settle midstream oil market based contracts on an aggregate
volume of 1.3 million barrels (2007 – 0.4 million barrels) and paid $13.1
million (2007 - $16.8 million) to settle midstream natural gas market based
contracts on an aggregate volume of 6.7 million gj’s (2007 – 6.6 million
gj’s).  In addition, Provident received $34.2 million (2007 – paid
$26.6 million) to settle midstream NGL market based contracts on an aggregate
volume of 0.2 million barrels (2007 – 2.4 million barrels).
 
 Provident
also paid $1.8 million (2007 – received $4.6 million) to settle
midstream-related foreign exchange contracts, and received $0.8 million (2007 –
nil) to settle various electricity-based contracts.
 
 iii)  Corporate
 
 a)  Foreign
exchange contracts
 
 For the
quarter ending December 31, 2008 Provident received $21.6 million (2007 - nil)
to settle various corporate-related foreign exchange based
contracts.  Realized gains and losses on corporate-related foreign
exchange contracts are included in foreign exchange (gain) loss and other on the
consolidated statement of operations and are allocated to the reporting segments
for segmented reporting purposes.  The gain in 2008 relates primarily
to contracts put in place to mitigate the foreign exchange risk associated with
U.S.-denominated taxes payable in connection with the sale of discontinued
operations (USOGP).
 
 Provident’s
Commodity Price Risk Management activities are also discussed in the year over
year section of Management’s Discussion and Analysis and in note 13 to the
consolidated financial statements.
   Provident
Energy 2008 Management’s Discussion and Analysis
 - 6
-
 
 Provident
Upstream segment review
 
 Crude
oil and natural gas liquids prices
  Provident
      Upstream
                
                Three
      months ended December 31,($
      per bbl)
                
                2008
                
                
                2007
                
                
                %
      ChangeOil
      per barrelWTI
      (US$)
                
                $
                58.73
                
                
                $
                90.68
                
                
                
                (35
                )Exchange
      rate (from US$ to Cdn$)
                
                $
                1.21
                
                
                $
                0.98
                
                
                
                23WTI
      expressed in Cdn$
                
                $
                71.21
                
                
                $
                89.03
                
                
                
                (20
                )Realized
      pricing before financial derivative instrumentsCrude
      oil
                
                $
                47.33
                
                
                $
                61.75
                
                
                
                (23
                )Natural
      gas liquids
                
                $
                47.64
                
                
                $
                63.63
                
                
                
                (25
                )Crude
      oil and natural gas liquids
                
                $
                47.36
                
                
                $
                61.94
                
                
                
                (24
                )
  The above
prices are net of transportation expense.
 
 In the
fourth quarter of 2008 Provident’s realized oil and natural gas liquids price,
prior to the impact of financial derivative instruments, decreased by 24 percent
to $47.36 per barrel compared to $61.94 per barrel in the fourth quarter of
2007.  The decrease was related to a 35 percent lower US$ WTI crude
oil price partially offset by a weaker Canadian dollar.
 
 Natural
gas price
  Provident
      Upstream
                
                Three
      months ended December 31,($
      per mcf)
                
                2008
                
                
                2007
                
                
                %
      ChangeAECO
      monthly index (Cdn$ per mcf)
                
                $
                6.78
                
                
                $
                6.00
                
                
                
                13Corporate
      natural gas price per mcf before financial
                  derivative
      instruments (Cdn$)
                
                $
                6.63
                
                
                $
                6.08
                
                
                
                9
  The above
prices are net of transportation expense.
 
 Provident’s
fourth quarter 2008 realized natural gas price, prior to the impact of financial
derivative instruments, increased nine percent as compared to the fourth quarter
of 2007, lower than the increase in the benchmark AECO index price of 13
percent.  Provident’s gas portfolio includes aggregator contracts sold
on a term basis that can differ from the benchmark price and sells to the spot
market on monthly or daily indices and receives prices which take into account
heat content.
 
 Production
  Provident
      Upstream
                
                Three
      months ended December 31,2008
                
                
                2007
                
                
                %
      ChangeDaily
      productionCrude
      oil (bpd)
                
                
                12,307
                
                
                
                11,252
                
                
                
                9Natural
      gas liquids (bpd)
                
                
                1,134
                
                
                
                1,277
                
                
                
                (11
                )Natural
      gas (mcfd)
                
                
                80,450
                
                
                
                92,584
                
                
                
                (13
                )Oil
      equivalent (boed) (1)
                
                
                26,849
                
                
                
                27,960
                
                
                
                (4
                )(1)
      Provident reports equivalent production converting natural gas to oil on a
      6:1 basis.
  Production
decreased four percent to 26,849 boed during the fourth quarter of 2008 as
compared to 27,960 boed in 2007.  The decrease was primarily a result
of natural production declines, an eight-day third-party gas
pipeline
   Provident
Energy 2008 Management’s Discussion and Analysis
 - 7
-
 
 outage in
Northwest Alberta impacting approximately 24 mmcfed natural gas and associated
oil production.  As well, cold weather downtime had an impact on
production primarily in the Dixonville and Lloydminster areas.  The
decrease was partially offset by increased oil production from the Triwest
Energy Inc. (“Triwest”) acquisition on December 3, 2007, as well as an active
drilling and optimization program.  The Triwest acquisition is
included in the Southeast Saskatchewan core area.
 
 Production
for the fourth quarter of 2008 was weighted 50 percent natural gas, and 50
percent crude oil and natural gas liquids.  This compared to fourth
quarter 2007 production weighted 55 percent natural gas and 45 percent crude oil
and natural gas liquids.
 
 Provident
Upstream’s production summarized by core areas is as follows:
  Three
      months ended December 31,Provident
      Upstream
                
                2008
                
                
                2007
                
                
                %
      ChangeDaily
      Production - by area (boed) (1)West
      Central Alberta
                
                
                6,005
                
                
                
                6,775
                
                
                
                (11
                )Southern
      Alberta
                
                
                4,990
                
                
                
                5,493
                
                
                
                (9
                )Northwest
      Alberta
                
                
                4,283
                
                
                
                4,714
                
                
                
                (9
                )Dixonville
                
                
                3,750
                
                
                
                4,090
                
                
                
                (8
                )Southeast
      Saskatchewan
                
                
                2,866
                
                
                
                2,144
                
                
                
                34Southwest
      Saskatchewan
                
                
                1,208
                
                
                
                1,527
                
                
                
                (21
                )Lloydminster
                
                
                3,747
                
                
                
                3,217
                
                
                
                1626,849
                
                
                
                27,960
                
                
                
                (4
                )(1)
      Provident reports equivalent production converting natural gas to oil on a
      6:1 basis.
   Provident
Energy 2008 Management’s Discussion and Analysis
 - 8
-
 
 Revenue
and royalties
  Provident
      Upstream
                
                Three
      months ended December 31,($
      000s except per boe and mcf data)
                
                2008
                
                
                2007
                
                
                %ChangeOilRevenue
                
                $
                53,592
                
                
                $
                63,920
                
                
                
                (16
                )Realized
      gain (loss) on financial derivative instruments
                
                
                6,089
                
                
                
                (4,675
                )
                
                
                -Royalties
                
                
                (9,159
                )
                
                
                (12,491
                )
                
                
                (27
                )Net
      revenue
                
                $
                50,522
                
                
                $
                46,754
                
                
                
                8Net
      revenue (per barrel)
                
                $
                44.62
                
                
                $
                45.17
                
                
                
                (1
                )Royalties
      as a percentage of revenue
                
                
                17.1
                %
                
                
                19.5
                %Natural
      gasRevenue
                
                $
                49,088
                
                
                $
                51,766
                
                
                
                (5
                )Realized
      gain on financial derivative instruments
                
                
                2,130
                
                
                
                5,174
                
                
                
                (59
                )Royalties
                
                
                (7,643
                )
                
                
                (9,437
                )
                
                
                (19
                )Net
      revenue
                
                $
                43,575
                
                
                $
                47,503
                
                
                
                (8
                )Net
      revenue (per mcf)
                
                $
                5.89
                
                
                $
                5.58
                
                
                
                6Royalties
      as a percentage of revenue
                
                
                15.6
                %
                
                
                18.2
                %Natural
      gas liquidsRevenue
                
                $
                4,970
                
                
                $
                7,477
                
                
                
                (34
                )Royalties
                
                
                (1,299
                )
                
                
                (1,882
                )
                
                
                (31
                )Net
      revenue
                
                $
                3,671
                
                
                $
                5,595
                
                
                
                (34
                )Net
      revenue (per barrel)
                
                $
                35.19
                
                
                $
                47.62
                
                
                
                (26
                )Royalties
      as a percentage of revenue
                
                
                26.1
                %
                
                
                25.2
                %TotalRevenue
                
                $
                107,650
                
                
                $
                123,163
                
                
                
                (13
                )Realized
      gain on financial derivative instruments
                
                
                8,219
                
                
                
                499
                
                
                
                1,547Royalties
                
                
                (18,101
                )
                
                
                (23,810
                )
                
                
                (24
                )Net
      revenue
                
                $
                97,768
                
                
                $
                99,852
                
                
                
                (2
                )Net
      revenue (per boe)
                
                $
                39.58
                
                
                $
                38.81
                
                
                
                2Royalties
      as a percentage of revenue
                
                
                16.8
                %
                
                
                19.3
                %Note: the
      above revenue, net revenue and net revenue per boe figures are presented
      net of transportation expenses.
  In the
fourth quarter of 2008, Provident Upstream production revenue was $107.7
million, a decrease of 13 percent from $123.2 million in 2007.  The
decrease in revenue is a result of a four percent decrease in production and a
24 percent decrease in crude oil and natural gas liquids prices, partially
offset by a nine percent increase in Provident’s realized natural gas
price.  Total royalties, which are price sensitive
and affected by production levels, as a percentage of revenue decreased
reflecting the lower crude oil prices, lower gas production, and capital
expenditures on natural gas facilities.  The preceding factors, as
well as the $7.7 million increase in realized gains on financial derivative
instruments account for net revenue of $97.8 million in the fourth quarter of
2008, two percent below the $99.9 million recorded in the fourth quarter of
2007.  Net revenue per boe in the fourth quarter of 2008 was $39.58
per boe, an increase of two percent from $38.81 per boe in the fourth quarter of
2007.
   Provident
Energy 2008 Management’s Discussion and Analysis
 - 9
-
 
 Production
expenses
  Provident
      Upstream
                
                Three
      months ended December 31,($
      000s, except per boe data)
                
                2008
                
                
                2007
                
                
                %
      ChangeProduction
      expenses
                
                $
                37,159
                
                
                $
                29,644
                
                
                
                25Production
      expenses (per boe)
                
                $
                15.04
                
                
                $
                11.52
                
                
                
                31
  Fourth
quarter 2008 production expenses increased 25 percent to $37.2 million from
$29.6 million in the comparable 2007 quarter.  On a boe basis, quarter
over quarter production expenses increased by 31 percent to $15.04 per boe from
$11.52 per boe in the comparable 2007 quarter.  In general, industry
operating costs in the fourth quarter of 2008 trended above costs in the
comparable 2007 quarter.  Specific to Provident, operating costs for
crude oil production are higher on a per boe basis than natural gas production
and, in the fourth quarter of 2008, crude oil and natural gas liquids
contributed 50 percent of the production mix, up from 45 percent in the
comparable quarter.  As well, the increase reflects unscheduled
turnarounds in Northwest Alberta performed to take advantage of circumstances
resulting from the third-party pipeline outage.  This has a dual
impact on the boe metric as it couples increased costs with reduced production,
however it avoids offline production in future periods. In addition, unscheduled
turnarounds in Southeast and Southwest Saskatchewan and additional downhole
costs associated with well servicing during the cold weather in December had an
unfavorable impact on operating costs across all of the core areas.
 
 Operating
netback
  Provident
      Upstream
                
                Three
      months ended December 31,($
      per boe)
                
                2008
                
                
                2007
                
                
                %
      ChangeNetback
      per boeGross
      production revenue
                
                $
                43.58
                
                
                $
                47.88
                
                
                
                (9
                )Royalties
                
                
                (7.33
                )
                
                
                (9.26
                )
                
                
                (21
                )Operating
      costs
                
                
                (15.04
                )
                
                
                (11.52
                )
                
                
                31Field
      operating netback
                
                
                21.21
                
                
                
                27.10
                
                
                
                (22
                )Realized
      gain on financial derivative instruments
                
                
                3.33
                
                
                
                0.19
                
                
                
                1,653Operating
      netback after realized financial derivative instruments
                
                $
                24.54
                
                
                $
                27.29
                
                
                
                (10
                )
  Provident
Upstream operating netbacks have transportation expense netted against gross
production revenue.
  The
fourth quarter 2008 field operating netback decreased 22 percent to $21.21 per
boe from $27.10 per boe in the comparable quarter in 2007.  The nine
percent drop in gross production revenue per boe reflects the 24 percent
decrease in crude oil and natural gas liquids prices combined with an increased
weighting of crude oil and natural gas liquids production to 50 percent from 45
percent in the comparable quarter in 2007.  This was partially offset
by the nine percent higher realized price for natural gas.  The 31
percent higher per boe production expenses is explained
above.  Royalties, which are price sensitive, decreased by 21 percent
on a boe basis reflecting the lower total liquids mix prices, prior to the
impact of financial derivative instruments.  The fourth quarter 2008
operating netback after financial derivative instruments decreased by 10 percent
to $24.54 from $27.29 reflecting the preceding factors as well as the 2008
fourth quarter gain on financial derivative instruments of $3.33 per boe
compared to $0.19 per boe in the comparable quarter in 2007.
   Provident
Energy 2008 Management’s Discussion and Analysis
 - 10
-
 
 General
and administrative
  Provident
      Upstream
                
                Three
      months ended December 31,($
      000s, except per boe data)
                
                2008
                
                
                2007
                
                
                %
      ChangeCash
      general and administrative
                
                $
                8,776
                
                
                $
                5,583
                
                
                
                57Non-cash
      unit based compensation
                
                
                (3,040
                )
                
                
                (3,014
                )
                
                
                1$
                5,736
                
                
                $
                2,569
                
                
                
                123Cash
      general and administrative (per boe)
                
                $
                3.55
                
                
                $
                2.17
                
                
                
                64
  Cash
general and administrative expenses for Provident Upstream in the fourth quarter
increased 57 percent to $8.8 million from $5.6 million recorded in the 2007
comparable quarter.  On a boe basis the cash general and
administrative expenses recorded in fourth quarter 2008 increased 64 percent to
$3.55 from $2.17 in the fourth quarter of 2007.  The increase in cash
general and administrative expenses is due to higher office-related expenses,
particularly rent, and costs associated with the previously announced strategic
evaluation of Provident’s business units, including an internal structural
reorganization completed in the fourth quarter of 2008.
 
 Non-cash
unit based compensation was a recovery of $3.0 million in the fourth quarter of
2008 and 2007.  The recovery reflects a reduction to employee
incentive costs due to lower unit prices and total return performance of the
Trust as measured against an industry peer group.
 
 Capital
expenditures
  Provident
      Upstream
                
                Three
      months ended December 31,($
      000s)
                
                2008
                
                
                2007Capital
      expenditures - by categoryGeological,
      geophysical and land
                
                $
                7,055
                
                
                $
                619Drilling
      and recompletions
                
                
                28,763
                
                
                
                37,485Facilities
      and equipment
                
                
                10,682
                
                
                
                5,827Office
      and other
                
                
                (4,067
                )
                
                
                8,614Total
      additions
                
                $
                42,433
                
                
                $
                52,545Capital
      expenditures - by areaWest
      central Alberta
                
                $
                3,383
                
                
                $
                2,159Southern
      Alberta
                
                
                6,113
                
                
                
                1,878Northwest
      Alberta
                
                
                22,561
                
                
                
                5,892Dixonville
                
                
                7,291
                
                
                
                26,130Southeast
      Saskatchewan
                
                
                4,166
                
                
                
                1,845Southwest
      Saskatchewan
                
                
                1,110
                
                
                
                2,913Lloydminster
                
                
                1,592
                
                
                
                3,383Other
                
                
                (3,783
                )
                
                
                8,345Total
      additions
                
                $
                42,433
                
                
                $
                52,545Property
      acquisitions, net
                
                $
                4,594
                
                
                $
                1,481
 
 In the
fourth quarter of 2008, Provident’s Upstream business unit spent $46.5 million
on capital expenditures before office and other capital
costs.  Internal development activities included 6.5 net wells drilled
during the quarter with a 100 percent success rate.  Provident was
most active in Northwest Alberta in the fourth quarter of 2008, spending $22.6
million on drilling and completion activities and facility work associated with
the start up of the 2008/2009 winter drilling program, directed towards the
emerging Pekisko opportunity.  In addition, 18.8 net sections
(approximately 12,000 acres) of undeveloped land was purchased to pursue the
Pekisko play.
 
 Provident
Energy 2008 Management’s Discussion and Analysis
 - 11
-
  Expenditures
in the Dixonville area were $7.3 million including 2.0 net horizontal wells
drilled.  Dixonville spending was lower as the primary drilling of the
pool was completed last year and expenditures have been directed towards the
full field waterflood program that is awaiting regulatory approval to advance
the project beyond the pilot stage.   In Southeast Saskatchewan,
$4.2 million was spent primarily on its drilling and completion program which
targeted light oil drilling on the Triwest assets resulting in 1.8 net wells
drilled.  The $12.4 million of capital spent in the remaining areas
included drilling, completion, tie-ins, recompletions, facility upgrades and
production optimization activities.
 
 In the
fourth quarter of 2008, Provident also spent $4.6 million on property
acquisitions relating to additional working interests in Northwest
Alberta.
 
 In
addition, $4.1 million was received in the fourth quarter of 2008 related to a
recovery of leasehold improvement costs to occupy the new head office
space.
 
 Depletion,
depreciation and accretion (DD&A)
  Provident
      Upstream
                
                Three
      months ended December 31,($
      000s, except per boe data)
                
                2008
                
                
                2007
                
                
                %
      ChangeDD&A
                
                $
                76,527
                
                
                $
                70,865
                
                
                
                8DD&A
      (per boe)
                
                $
                30.98
                
                
                $
                27.55
                
                
                
                12
 
 The
Provident Upstream DD&A rate of $30.98 per boe for the fourth quarter of
2008 increased by 12 percent compared to $27.55 per boe for the fourth quarter
of 2007.  The increase was primarily due to 2008 expenditures on
geological, geophysical, land and facilities, which added to costs to be
depleted without directly adding proved reserves, and as a result of the
acquisition of Triwest in December 2007.
 
 Accretion
expense associated with asset retirement obligations was $0.9 million in the
fourth quarter of 2008 compared to $0.7 million in the fourth quarter of
2007.
   Provident
Energy 2008 Management’s Discussion and Analysis
 - 12
-
 
 Provident
Midstream business segment review
 
 The
Midstream business
 
 The
Midstream business unit extracts, processes, stores, transports and markets
natural gas liquids (NGL) for Provident and offers these services to third party
customers.  The Provident Midstream segment contains three business
lines:
  Empress
East
 Redwater
West
 Provident
Commercial Services.
 
 Provident
Midstream business unit results can be summarized as follows:
  Three
      months ended December 31,($
      000s)
                
                2008
                
                
                2007
                
                
                %
      ChangeEmpress
      East Margin
                
                $
                900
                
                
                $
                77,110
                
                
                
                (99
                )Redwater
      West Margin
                
                
                4,142
                
                
                
                41,709
                
                
                
                (90
                )Commercial
      Services Margin
                
                
                12,095
                
                
                
                19,587
                
                
                
                (38
                )Gross
      operating margin
                
                
                17,137
                
                
                
                138,406
                
                
                
                (88
                )Realized
      gain (loss) on financial derivative instruments
                
                
                16,098
                
                
                
                (38,631
                )
                
                
                -Cash
      general and administrative expenses
                
                
                (8,418
                )
                
                
                (6,355
                )
                
                
                32Foreign
      exchange gain (loss) and other
                
                
                12,849
                
                
                
                (3,997
                )
                
                
                -Provident
      Midstream EBITDA
                
                $
                37,666
                
                
                $
                89,423
                
                
                
                (58
                )
  Gross
operating margin
 
 The
Empress East business line extracts NGLs from natural gas at the Empress
straddle plants and sells finished products into markets in Central Canada and
the Eastern United States. The margin in this business is determined primarily
by the “frac spread ratio”, which is the ratio between crude oil prices and
natural gas prices. Traditionally the higher the ratio, the better this business
line will perform.  There is also a differential between propane,
butane and condensate (collectively, these products are referred to as
“propane-plus”) prices and crude oil prices which can change prices received and
margins realized for Midstream products separate from frac spread ratio
changes.  Operating margins reflect the prices realized on sale of
these products less the weighted average cost of purchasing, fractionating,
storing and transporting the products.  The business is seasonal and
carries inventory that generally builds over the second and third quarters of
the year and is sold in the fourth quarter and the first quarter of the
following year.
 
 In the
fourth quarter of 2008, the gross operating margin for Empress East was $0.9
million (2007 - $77.1 million).  This decrease reflects the operating
margin squeeze that resulted from both a dramatic drop in prices received for
product sales compounded by a high per unit cost of inventory entering the
fourth quarter of 2008. Prices received in the fourth quarter of 2008 for
propane-plus products were 42 percent lower than the fourth quarter of 2007 and
tracked the significant decrease in crude oil prices.  The average
frac spread ratio in the fourth quarter of 2008 was 11.2, 29 percent below the
average of 15.7 in the fourth quarter of 2007.  A further driver for
the drop in 2008 fourth quarter gross operating margin was that, as winter sales
demand for propane increased late in the quarter, the frac spread ratio had
deteriorated significantly, from 15.4 in October to 7.6 in
December.  In addition to lower frac spread ratios, the fourth quarter
experienced a significant decline in the sales price of propane relative to the
price of crude oil.  Posted prices at Mont Belvieu for propane in the
fourth quarter of 2008 averaged 57 percent of WTI (U.S. $58.73), compared to 70
percent of WTI (U.S. $90.68) in the comparable quarter of
2007.   A final factor on the sales side, sales volumes in the
fourth quarter of 2008 for propane-plus products was nine percent lower than the
fourth quarter of 2007.
   Provident
Energy 2008 Management’s Discussion and Analysis
 - 13
-
 
 Further
contributing to the reduced operating margins for Empress East in the quarter
was the cost of product available for sale.  The costs in the fourth
quarter of 2008 reflected opening inventory balances that built up in the second
and third quarter of 2008, when natural gas prices at AECO averaged $9.30 per
mcf, 43 percent above the $6.49 per mcf average natural gas price for the
comparable 2007 quarters.  This, combined with continuing to build
inventory in a falling market in the fourth quarter of 2008, drove an eight
percent increase in cost of goods sold, on a per unit basis, over the
comparative quarter of 2007.
 
 Subsequent
to year end, conditions have shown some improvement.  The frac spread
ratio in January 2009 has recovered to 8.3, and the price of propane as a
percentage of WTI increased to 72 percent.  As well, the weighted
average cost of inventory at December 31, 2008 on a per unit basis was 13
percent below the per unit cost of inventory at September 30, 2008.
 
 The
Redwater West business line purchases an NGL mix from various producers and
fractionates it into finished products at the Redwater fractionation facility
near Edmonton, Alberta.  Because the feedstock for this business line
is primarily NGL mix rather than natural gas, the frac spread ratio has a
smaller impact on margin than in the Empress East business line.  This facility
also has the largest rail rack in Western Canada to receive products for
delivery into the local condensate market.  Provident has considerably
increased its participation in the condensate market over the past year,
reflecting the increased diluent demand for heavy oil production.
 
 In the
fourth quarter of 2008, the operating margin for Redwater West was $4.1 million
(2007 - $41.7 million).  The decrease in margin is primarily due to 40
percent lower selling prices tracking the significant drop in crude oil prices,
as well as the deterioration in the price of NGL products as a percentage of
WTI.  Cost of goods sold also declined reflecting the market based
pricing for the majority of this product.  The decrease in cost of
goods sold, on a per unit basis, for Redwater West was 31 percent, when compared
to the fourth quarter of 2007, which is less than the decline in related selling
prices.  In periods of falling market prices, cost of goods sold in
Redwater West generally does not decline as fast as revenue.  This is
due to the fact that inventory, which was built up in prior periods when prices
were higher, is being sold in a declining price environment.   A
volume increase of nine percent was primarily related to
condensate.
 
 The
Commercial Services business line generates income from stable fee-for-service
contracts to provide fractionation, storage, loading, and marketing services to
upstream producers.  Income from pipeline tariffs from Provident’s
ownership in NGL pipelines is also included in this business line.  In
the fourth quarter of 2008, the margin for this business line was $12.1 million
(2007 - $19.6 million).  The 2008 fourth quarter operating margin,
while 38 percent lower for this business line than the 2007 comparable quarter,
does incorporate a 53 percent increase in the fees associated with the
offloading facility, due to increased condensate business.   The
fourth quarter of 2007 included an anomaly whereby Commercial Services benefited
from payments for product quality adjustments related to our condensate
offloading facility that covered prior quarters.  These payments
increased the fourth quarter operating margin in 2007, are generally
non-recurring and account for the quarter over quarter decrease in operating
margin.
 
 Operations
– Provident Midstream NGL sales volumes
 
 Provident
Midstream sold 120,222 bpd in the fourth quarter of 2008, down 12 percent when
compared with the fourth quarter of 2007.  Decreased propane-plus
volumes in Empress East were largely offset by increased propane-plus volumes in
Redwater West.  Lower overall sales volume reflects lower sales of
ethane due to reduced demand in the quarter.
 
 Earnings before interest, taxes,
depletion, depreciation, accretion, and other non-cash items (“EBITDA”)
and funds flow from
operations
 
 Fourth
quarter 2008 EBITDA of $37.7 million decreased $51.7 million or 58 percent from
$89.4 million in the fourth quarter of 2007. A $121.3 million decrease in gross
operating margin as described above was partially offset by a $54.7 million
increase in realized gains on financial derivative instruments, when compared
with the fourth quarter of 2007 as well as foreign exchange gains on U.S.
dollar-based transactions.  Funds flow from operations for the fourth
quarter of 2008 was $34.6 million, a decrease of $42.5 million or 55 percent
compared to the $77.1
   Provident
Energy 2008 Management’s Discussion and Analysis
 - 14
-
 
 million
for the fourth quarter 2007.  The decrease in funds flow from
operations reflects lower EBITDA partially offset by lower interest charges and
higher income tax recoveries.
 
 Cash
general and administrative expenses and other were $8.4 million in the fourth
quarter of 2008, an increase of $2.1 million compared with $6.3 million in the
fourth quarter of 2007.  The increase is due to higher office-related
expenses, particularly rent, and costs associated with the previously announced
strategic evaluation of Provident’s business units, including an internal
structural reorganization completed in the fourth quarter of 2008.
 
 Management
uses EBITDA to analyze the operating performance of the Provident Midstream
business unit.  EBITDA as presented does not have any standardized
meaning prescribed by Canadian GAAP and therefore it may not be comparable with
the calculation of similar measures for other entities. EBITDA as presented is
not intended to represent operating cash flow from operations or operating
profits for the period nor should it be viewed as an alternative to cash flow
from operations from operating activities, net earnings or other measures of
financial performance calculated in accordance with Canadian
GAAP.  All references to EBITDA throughout this report are based on
earnings before interest, taxes, depletion, depreciation, accretion, and other
non-cash items (“EBITDA”).
 
 Capital
expenditures
 
 Provident
Midstream capital expenditures for the fourth quarter of 2008 totaled $12.5
million.  In the quarter, $12.8 million was spent on the condensate
offloading and terminalling facility, expansion to the recently completed truck
loading facilities, and continued development of cavern storage.  In
addition, $1.9 million was spent on sustaining capital requirements and a $2.2
million recovery was received on office furniture and
equipment.
   Provident
Energy 2008 Management’s Discussion and Analysis
 - 15
-
 
 2008 Year end
results
  Consolidated
funds flow from operations and cash distributions
  Consolidated
                Year
      ended December 31,($
      000s, except per unit data)
                
                2008
                
                
                2007
                
                
                %
      ChangeFunds
      Flow from Operations and DistributionsFunds
      flow from continuing operations
                
                $
                517,622
                
                
                $
                382,684
                
                
                
                35Funds
      flow from discontinued operations (USOGP)(1)
                
                
                137,535
                
                
                
                85,571
                
                
                
                61Total
      funds flow from operations
                
                $
                655,157
                
                
                $
                468,255
                
                
                
                40Per
      weighted average unit - basic and diluted (2)
                
                $
                2.57
                
                
                $
                2.04
                
                
                
                26Declared
      distributions
                
                $
                352,291
                
                
                $
                333,352
                
                
                
                6Per
      Unit
                
                $
                1.38
                
                
                $
                1.44
                
                
                
                (4
                )Percent
      of funds flow from operations distributed(3)
                
                
                58
                %
                
                
                77
                %
                
                
                (25
                )(1)Prior to the sale of
      USOGP, Provident owned approximately 22 per cent of the BreitBurn Energy
      Partners, L.P. (MLP) and96
      per cent of BreitBurn Energy Company L.P. In accordance with
      generally accepted accounting principles (GAAP) inCanada
      and the United States, these investments were
                  consolidated into Provident's results. On a proportionate
      basis,Provident's
      share of funds flow from operations related to discontinued operations
      (USOGP) for the year endedDecember
      31, 2008 was $57.9 million.(2)Includes dilutive impact of unit options and convertible
      debentures.(3)Calculated as declared distributions to unitholders divided by
      funds flow from operations less distributions to
      non-controllinginterests
      of $51.4 million (2007 - $35.8 million).
 
 Management
uses funds flow from operations to analyze operating
performance.  Funds flow from operations represents cash flow from
operations before changes in working capital and site restoration
expenditures.  Provident also reviews funds flow from operations in
setting monthly distributions and takes into account cash required for debt
repayment and/or capital programs in establishing the amount to be distributed
to Unitholders.
 
 Funds
flow from operations as presented does not have any standardized meaning
prescribed by Canadian generally accepted accounting principles (GAAP) and
therefore it may not be comparable with the calculations of similar measures for
other entities.  Funds flow from operations as presented is not
intended to represent cash flow from operations or operating profits for the
period nor should it be viewed as an alternative to cash provided by
operating activities, net earnings or other measures of financial performance
calculated in accordance with Canadian GAAP.  All references to funds
flow from operations throughout this report are based on cash provided by
operating activities before changes in non-cash working capital and site
restoration expenditures.
 
 For the
year ended December 31, 2008, funds flow from operations increased $186.9
million or 40 percent to $655.2 million from $468.3 million for
2007.  On a per unit basis, funds flow from operations increased 26
percent in 2008 to $2.57 per unit from $2.04 per unit in
2007.  Provident Upstream generated $338.7 million, Provident
Midstream $179.0 million and discontinued operations (USOGP) contributed $137.5
million of funds flow from operations during 2008.  During 2007,
Provident Upstream generated funds flow from operations of $204.3 million,
Provident Midstream $178.4 million, and discontinued operations (USOGP) $85.6
million.
 
 Canadian
oil and gas operations contributed funds flow from operations of $338.7 million
in 2008, an increase of $134.4 million or 66 percent when compared with $204.3
million from 2007.  This increase was the result of higher realized
crude oil, natural gas liquids and natural gas prices in the first nine months
of 2008, combined with an increase in production.
 
 The
Midstream business unit added $179.0million to
2008 funds flow from operations, compared with $178.4 million recorded in the
year ended December 31, 2007.  Midstream funds flow from operations
reflects a decrease in EBITDA of $12.9 million or six percent, offset by reduced
cash interest charges due to lower debt levels and a reduction in current taxes
compared to 2007.
   Provident
Energy 2008 Management’s Discussion and Analysis
 - 16
-
 
 For the
year ended December 31, 2008, funds flow from discontinued operations (USOGP)
was $137.5 million, compared to the $85.6 million in
2007.  The increase is primarily driven by increased production due to
oil and gas property acquisitions by the MLP in 2007, combined with higher
commodity prices.  Prior to the sale of USOGP, Provident owned
approximately 22 percent of the MLP and 96 percent of BreitBurn.  In
accordance with generally accepted accounting principles (GAAP) in Canada and
the United States, these investments were consolidated into Provident's
results.  On a proportionate basis, Provident's share of funds flow
from operations relating to discontinued operations (USOGP) for the year ended
December 31, 2008 was $57.9 million.  Management uses
proportionate information to analyze operating performance.  The
proportionate information as presented here does not have any standardized
meaning prescribed by Canadian GAAP and therefore may not be comparable with the
calculation of similar measures for other entities.  This
proportionate information is not intended to be viewed as an alternative to the
corresponding measures of financial performance calculated in accordance with
Canadian GAAP.
 
 Declared
distributions in 2008 totaled $352.3 million, 58 percent of funds flow from
operations, after distributions to non-controlling interests of $51.4
million.  This compares to $333.4 million of declared distributions in
2007, 77 percent of funds flow from operations, after distributions to
non-controlling interests of $35.8 million.  In previous years,
Provident has paid out between 67 percent and 102 percent of its annual funds
flow from operations as distributions to unitholders.  On a segmented
basis, the Midstream business, due to its low sustaining capital requirements,
effectively contributed 95 percent of its funds flow from operations for
distribution in the year ended December 31, 2008.  The remaining
distributions were effectively contributed by the oil and natural gas production
businesses (Provident Upstream and USOGP) representing 43 percent of their
combined funds flow from operations in 2008.
 
 Outlook
  Continued
price weakness and volatility in commodity markets is having a negative impact
on the energy industry on a global scale. This market turmoil has resulted in
reduced capital investment, activity levels and ongoing uncertainty in debt and
equity markets in the first quarter of 2009. In the current environment, energy
firms such as Provident will be challenged to generate cash flow comparable to
levels achieved in recent years. Provident actively monitors commodity prices
and market conditions on an ongoing basis and will continue to balance
reinvestment of cash flow among capital expenditures, distributions and long
term debt.
  Provident
Upstream has a 2009 capital budget of $88 million and plans to drill a total of
23.8 net wells. Approximately $36 million is being directed towards development
of the Pekisko medium oil play in Northwest Alberta. Three new Pekisko wells
have been drilled and surface facilities are now being installed that will
enable year round production from four of the five Pekisko wells beginning in
the second quarter of 2009. Approximately $19 million is allocated to the
implementation of the first phase of the waterflood project in Dixonville. The
remaining $33 million is budgeted for development initiatives in other areas.
2009 production is expected to average between 23,500 and 25,000 barrels of oil
equivalent per day (boed). Subject to pricing assumptions, royalty rates are
expected to fall this year to approximately 17 percent including the impact of
the new Alberta royalty framework. Operating costs are expected to remain
relatively stable in the first half of 2009, but should begin to moderate in the
latter half of the year as labour, service and material costs deflate as
development activity slows.
  Provident
Midstream has a 2009 capital budget of approximately $27 million. This budget
will be used, in part, to complete two 500,000 barrel condensate caverns which
will enter service at the Redwater facility in the summer of 2009. Work also
continues on a third cavern of equal size that is expected to be complete in
2011. Upon completion of these caverns, Provident will own 6.6 million barrels
of underground product storage at Redwater. A portion of the 2009 capital budget
will be directed towards certain facility optimization and debottlenecking
initiatives while approximately $6 million will be used for normal course
facility maintenance. Provident is also allocating a portion of its 2009 capital
budget towards the initial phases of a project to construct a depropanizer
facility located in Michigan. The Michigan depropanizer is one of several
options under consideration to mitigate the financial impact of the potential
6,000 barrels per day curtailment of NGL fractionation capacity at Sarnia which
would take effect April 1, 2009, contingent on ongoing contractual negotiations
with the facility owner.
   Provident
Energy 2008 Management’s Discussion and Analysis
 - 17
-
 
 NGL
margins have strengthened in the first quarter of 2009 compared to the fourth
quarter of 2008. This improvement is the result of substantially higher sale
prices for propane and butane due to strong winter demand coupled with a lower
cost of sales as the majority of the high cost inventory accumulated during 2008
has been depleted.
  Distributions
  The
following table summarizes distributions paid as declared by the Trust since
inception:
  Distribution
      AmountRecord
      Date
                Payment
      Date
                
                (Cdn$)
                
                
                (US$)*2008January
      24, 2008
                February
      15, 2008
                
                $
                0.12
                
                
                
                0.12February
      25, 2008
                March
      14, 2008
                
                
                0.12
                
                
                
                0.12March
      24, 2008
                April
      15, 2008
                
                
                0.12
                
                
                
                0.12April
      22, 2008
                May
      15, 2008
                
                
                0.12
                
                
                
                0.12May
      23, 2008
                June
      13, 2008
                
                
                0.12
                
                
                
                0.12June
      20, 2008
                July
      15, 2008
                
                
                0.12
                
                
                
                0.12July
      22, 2008
                August
      15, 2008
                
                
                0.12
                
                
                
                0.12August
      22, 2008
                September
      15, 2008
                
                
                0.12
                
                
                
                0.11September
      22, 2008
                October
      15, 2008
                
                
                0.12
                
                
                
                0.10October
      22, 2008
                November
      14, 2008
                
                
                0.12
                
                
                
                0.10November
      25, 2008
                December
      15, 2008
                
                
                0.09
                
                
                
                0.07December
      22, 2008
                January
      15, 2009
                
                
                0.09
                
                
                
                0.072008
      Cash Distributions paid as declared
                
                
                $
                1.38
                
                
                
                1.292007
      Cash Distributions paid as declared
                
                
                
                1.44
                
                
                
                1.352006
      Cash Distributions paid as declared
                
                
                
                1.44
                
                
                
                1.262005
      Cash Distributions paid as declared
                
                
                
                1.44
                
                
                
                1.202004
      Cash Distributions paid as declared
                
                
                
                1.44
                
                
                
                1.102003
      Cash Distributions paid as declared
                
                
                
                2.06
                
                
                
                1.472002
      Cash Distributions paid as declared
                
                
                
                2.03
                
                
                
                1.292001
      Cash Distributions paid as declared
                  –
      March 2001 – December 2001
                
                
                2.54
                
                
                
                1.64Inception
      to December 31, 2008 – Distributions paid as declared
                
                $
                13.77
                
                
                
                10.60*
      Exchange rate based on the Bank of Canada noon rate on the payment
      date.
  For
Canadian tax purposes, 2008 distributions were determined to be 100 percent
taxable with no tax deferred return of capital in the hands of Canadian
unitholders.  The 2007 comparables were 94.8 percent taxable and 5.2
percent tax deferred return of capital.  Distributions received by
U.S. resident unitholders in 2008 were considered to be 100 percent qualified
dividend with no tax deferred return of capital.  The 2007 comparables
were considered to be 97.6 percent qualified dividend and 2.4 percent tax
deferred return of capital.  In both Canada and the U.S., any
tax-deferred portion would usually be treated as an adjustment to the cost base
of the units.  Unitholders or potential unitholders should consult
their own legal or tax advisors as to their particular income tax consequences
of holding Provident units.
 
 Net
income
  Consolidated
                Year
      ended December 31,($
      000s, except per unit data)
                
                2008
                
                
                2007
                
                
                %
      ChangeNet
      income
                
                $
                157,392
                
                
                $
                30,434
                
                
                
                417Per
      weighted average unit
                  –
      basic (1)and diluted(2)
                
                $
                0.62
                
                
                $
                0.13
                
                
                
                377(1)
      Based on weighted average number of trust units
    outstanding.(2)Based on weighted average number of trust units outstanding
      including the dilutive impact of the unit option plan and
      convertibledebentures.
   Provident
Energy 2008 Management’s Discussion and Analysis
 - 18
-
 
 Consolidated
                
                Year
      ended December 31,($
      000s)
                
                2008
                
                
                2007
                
                
                %
      ChangeProvident
      Upstream net (loss) income
                
                $
                (306,050
                )
                
                $
                45,065
                
                
                
                -Provident
      Midstream net income (loss)
                
                
                317,418
                
                
                
                (161,020
                )
                
                
                -Net
      income (loss) from continuing operations
                
                $
                11,368
                
                
                $
                (115,955
                )
                
                
                -Net
      income from discontinued operations (USOGP)
                
                
                146,024
                
                
                
                146,389
                
                
                
                -Consolidated
      net income
                
                $
                157,392
                
                
                $
                30,434
                
                
                
                417
 
 Net
income for the year ended December 31, 2008 increased to $157.4 million compared
to $30.4 million of net income in 2007.  On a consolidated basis, the
increase in net income in 2008 was driven by favorable operating results
compared to 2007 as well as a $435.7 million change to unrealized gain (loss) on
financial derivative instruments, partially offset by a $416.9 million non-cash
goodwill impairment charge (see “Goodwill”).
 
 The
Provident Upstream business segment’s net loss was $306.0 million, a $351.0
million decrease compared with year ended December 31, 2007 net income of $45.0
million.  A $131.7 million increase in EBITDA and a $51.5 million
increase in unrealized gains on financial derivative instruments were more than
offset by a non-cash goodwill impairment charge of $416.9 million and, to a
lesser extent, increased depletion, depreciation and accretion (DD&A) and a
decrease in future income tax recoveries.
 
 The
Provident Midstream segment recorded net income of $317.4 million as compared to
a net loss of $161.0 million in the year ended December 31, 2007.  In
2008, Provident Midstream generated a $14.5 million, or four percent increase in
gross operating margin over 2007, reflecting the positive price environment in
the first nine months of the year and a $23.8 million increase over 2007 in
foreign exchange gains on U.S. dollar based transactions.  These
increases were offset by a $44.4 million increase in realized losses on
financial derivative instruments.  However, the income was primarily
attributable to the requirement under generally accepted accounting principles
(GAAP) to “mark-to-market” all financial derivative instruments at a point in
time and report these unrealized gains or losses as part of current period
income.  In 2008, this resulted in $191.2 million of additional income
before future income taxes compared to a $192.9 million reduction in income
before future income taxes in 2007, representing a $384.2 million swing in
unrealized gains on financial derivative instruments over the two year
period.  Because Provident’s commodity price risk management program
involves the use of financial derivative instruments with terms that extend up
to five years into the future in the Midstream segment, net earnings can show
substantial variation that is not necessarily related to current
operations.  In addition, a $73.7 million decrease in future tax
expense contributed to the increase in Provident Midstream net
income.
 
 Net
income from discontinued operations (USOGP) in 2008 was $146.0 million as
compared to $146.4 million in 2007.  The 2008 net income is primarily
driven by gains on sale of the discontinued operations, amounting to $263.6
million.  Net income from discontinued operations in 2007 included a
dilution gain of $260.3 million recognized as MLP units were issued to third
parties to finance growth.
 
 Reconciliation
of non-GAAP measures
  The Trust
calculates earnings before interest, taxes, depletion, depreciation, accretion
and other non-cash items (EBITDA) within its segment disclosure. EBITDA is a
non-GAAP measure.  A reconciliation between EBITDA and loss from
continuing operations before taxes follows:
  Year
      ended December 31,($
      000s)
                
                2008
                
                
                2007
                
                
                %
      ChangeEBITDA
                
                $
                566,254
                
                
                $
                447,427
                
                
                
                27Adjusted
      for:Cash
      interest
                
                
                (50,793
                )
                
                
                (54,181
                )
                
                
                (6
                )Unrealized
      gain (loss) on financial derivative instruments
                
                
                221,468
                
                
                
                (214,244
                )
                
                
                -Goodwill
      impairment
                
                
                (416,890
                )
                
                
                -
                
                
                
                -Depletion,
      depreciation and accretion and other non-cash expenses
                
                
                (339,856
                )
                
                
                (313,199
                )
                
                
                9Loss
      from continuing operations before taxes
                
                $
                (19,817
                )
                
                $
                (134,197
                )
                
                
                (85
                )
   Provident
Energy 2008 Management’s Discussion and Analysis
 - 19
-
 
 The
following table reconciles funds flow from operations with cash provided by
operating activities and distributions to unitholders:
  Reconciliation
      of funds flow from operations to distributions
                
                Year
      ended December 31,($
      000s, except per unit data)
                
                2008
                
                
                2007
                
                
                %
      ChangeCash
      provided by operating activities
                
                $
                674,426
                
                
                $
                464,455
                
                
                
                45Change
      in non-cash operating working capital
                
                
                (25,650
                )
                
                
                (262
                )
                
                
                9,690Site
      restoration expenditures
                
                
                6,381
                
                
                
                4,062
                
                
                
                57Funds
      flow from operations
                
                
                655,157
                
                
                
                468,255
                
                
                
                40Distributions
      to non-controlling interests
                
                
                (51,433
                )
                
                
                (35,846
                )
                
                
                43Cash
      retained for financing and investing activities
                
                
                (251,433
                )
                
                
                (99,057
                )
                
                
                154Distributions
      to unitholders
                
                
                352,291
                
                
                
                333,352
                
                
                
                6Accumulated
      cash distributions, beginning of year
                
                
                1,260,177
                
                
                
                926,825
                
                
                
                36Accumulated
      cash distributions, end of year
                
                $
                1,612,468
                
                
                $
                1,260,177
                
                
                
                28Cash
      distributions per unit
                
                $
                1.38
                
                
                $
                1.44
                
                
                
                (4
                )
  Taxes
  Year
      ended December 31,($
      000s)
                
                2008
                
                
                2007
                
                
                %
      ChangeCapital
      tax expense
                
                $
                3,109
                
                
                $
                3,762
                
                
                
                (17
                )Current
      and withholding tax (recovery) expense
                
                
                (4,529
                )
                
                
                6,352
                
                
                
                -Future
      income tax recovery
                
                
                (29,765
                )
                
                
                (28,356
                )
                
                
                5$
                (31,185
                )
                
                $
                (18,242
                )
                
                
                71
 
 Capital
taxes in 2008 totaled $3.1 million, a decrease from the $3.8 million expense
recorded in 2007.  The decrease reflects upward adjustments made in
2007 upon filing of previous years tax returns.
 
 The
current and withholding tax recovery of $4.5 million in 2008 compares to $6.4
million expense in 2007.  The decrease in current taxes was due to
lower income subject to tax in the U.S.-based Midstream operations.
 
 For the
year ended December 31, 2008, future income tax recovery was $29.8 million,
compared with a recovery of $28.4 million in 2007.  In 2008,
additional future tax recoveries were recorded as a result of an internal
structural reorganization as well as losses created by interest and royalty
deductions at the incorporated subsidiary level, offset by future tax expense
relating to unrealized gains on financial derivative instruments.  The
goodwill impairment charge in 2008 had no impact on future income
taxes.  The 2007 future income tax recovery includes $88.4 million of
expense relating to the enactment of legislation to tax publicly traded trusts
in 2011 offset by future tax recoveries created by interest and royalty
deductions at the incorporated subsidiary level.
 
 In 2007,
future income tax expense included $88.4 million relating to the enactment of
Bill C-52, Budget Implementation Act 2007 by the Canadian
government.  This bill contains legislation to tax publicly traded
trusts including Provident.  The legislation limits the tax
deductibility of cash distributions after 2010 such that income taxes may become
payable in the future.  As a result of this legislation, the Trust is
required to record the future tax effect of the temporary differences on its
flow through entities that are expected to reverse subsequent to
2010.
 
 The Trust
has estimated its future income taxes based on estimates of results of
operations and tax pool claims and cash distributions in the future assuming no
material change to the Trust’s current organizational structure.  The
Trust’s estimate of future income taxes does not incorporate any assumptions
related to a change in organizational structure until such structures are given
legal effect.
 
 The
Trust’s estimate of its future income taxes will vary as do the Trust’s
assumptions pertaining to the factors described above, and such variations may
be material.
  
 Provident
Energy 2008 Management’s Discussion and Analysis
 - 20
-
 
 
 The
legislation will not affect the Trust’s cash flows from operations and
accordingly the Trust’s financial condition until 2011, based on our planned
compliance with the legislated growth guidelines.
 
 The Trust
has approximately $1.4 billion in tax pools available to claim against taxable
income.  Provident plans to manage discretionary tax pool claims to
defer payment of current taxes as long as possible.  Provident has
made estimates of taxability in future years based on a number of assumptions
including:  future product prices; future production and sales; future
operating and product costs; future general and administrative costs; future
capital expenditures; and general business conditions.  Using these
assumptions about future events which may or may not occur, Provident estimates
that:
 
 ·
              current
      taxes on Canadian oil and gas operations would occur after 2016;
      and
 ·
              current
      taxes for midstream operations would occur in
  2011.
 
 Provident’s
tax pools available to shelter future income as at December 31, 2008 are
estimated as follows:
  As
      at December 31, 2008($
      000s)
                
                Provident
                  Upstream
                
                
                Provident
                  Midstream
                
                
                TotalIntangibles
                
                $
                610,000
                
                
                $
                -
                
                
                $
                610,000Tangibles
                
                
                265,000
                
                
                
                270,000
                
                
                
                535,000Non-capital
      losses
                
                
                260,000
                
                
                
                10,000
                
                
                
                270,000$
                1,135,000
                
                
                $
                280,000
                
                
                $
                1,415,000
  Provident
also has capital losses of approximately $370 million which are available to
reduce the tax effect of future capital gains.
 
 Interest
expense
 
 Continuing
      operations
                
                Year
      ended December 31,($
      000s, except as noted)
                
                2008
                
                
                2007
                
                
                %
      ChangeInterest
      on bank debt
                
                $
                35,044
                
                
                $
                42,477
                
                
                
                (17
                )Interest
      on convertible debentures
                
                
                19,934
                
                
                
                20,200
                
                
                
                (1
                )Discontinued
      operations portion
                
                
                (4,185
                )
                
                
                (8,496
                )
                
                
                (51
                )Total
      cash interest
                
                $
                50,793
                
                
                $
                54,181
                
                
                
                (6
                )Weighted
      average interest rate on all long-term debt
                
                
                5.3
                %
                
                
                5.8
                %
                
                
                (9
                )Debenture
      accretion and other non-cash interest expense
                
                
                5,239
                
                
                
                4,727
                
                
                
                11Total
      interest expense
                
                $
                56,032
                
                
                $
                58,908
                
                
                
                (5
                )
 
 Interest
expense decreased in 2008 compared to 2007 due to lower debt levels and lower
market interest rates. Cash proceeds on the sale of USOGP in June and August of
2008, amounting to $457.9 million, net of tax, were used to pay down
debt.
   Provident
Energy 2008 Management’s Discussion and Analysis
 - 21
-
 
 Financial
instruments
 
 Commodity
price risk management program
 
 For the
year ended December 31, 2008 $130.0 million was recorded as a realized loss
on financial derivative instruments due to the Commodity Price Risk Management
Program (the Program) with $11.1 million related to Provident Upstream
and $118.9 million associated with the Provident Midstream
segment.
 
 In the
Provident Upstream segment, the realized loss in 2008 associated with crude oil
and natural gas liquids totaled $11.1 million ($2.22 per barrel) and a
realized gain of nil related to natural gas.  The combined total was a
loss of $11.1 million or $1.10 per boe.  In 2007 the Program
recorded a realized loss of $7.9 million related to crude oil and natural
gas liquids ($1.95 per barrel) and a realized gain of $9.6 million related
to natural gas ($0.28 per mcf).  The combined 2007 total was a
gain of $1.7 million, or $0.18 per boe.
 
 In 2008
the Midstream segment recorded realized losses on crude oil contracts amounting
to $135.6 million (2007 – gains of $17.9 million), and realized losses of $17.0
million (2007 - $48.7 million) related to natural gas.  In addition,
realized gains associated with NGL market based contracts totaled $25.9 million
(2007 – losses of $48.2 million), realized gains on Midstream-related foreign
exchange contracts were $5.4 million (2007 - $4.6 million) and realized gains on
electricity-based contracts were $2.4 million (2007 – nil).
 
 Realized
gains on corporate-related foreign exchange contracts in 2008 related to the
Program were $26.8 million (2007 - $1.3 million).  Realized gains
and losses on corporate-related foreign exchange contracts are included in
foreign exchange (gain) loss and other on the consolidated statement of
operations and are allocated to the reporting segments for segmented reporting
purposes.  The gain in 2008 relates primarily to contracts put in
place to mitigate the foreign exchange risk associated with U.S.-denominated
taxes payable in connection with the sale of discontinued operations
(USOGP).
 
 On a per
trust unit basis the opportunity cost of the Program increased to $0.51 per
trust unit in 2008 from $0.32 per trust unit in 2007.  The
increased per unit cost in 2008 was more than offset by the funds flow from
operations generated by the business units in the high commodity price
environment and is reflected in the 26 percent increase in funds flow operations
on a per unit basis.  In the fourth quarter of 2008, when commodity
prices dropped dramatically, the Program helped to stabilize cash flow by
contributing $24.3 million, or 30 percent of fourth quarter funds flow from
operations.
  At
December 31, 2008 the mark-to-market value of open contracts was in a net loss
position of $54.7 million based upon commodity prices prevailing at that date.
Under generally accepted accounting principles, these unrealized
“mark-to-market” opportunity costs, which relate to financial derivative
positions with effective periods ranging from January 2009 through March 2013,
are required to be recognized in the financial statements of Provident,
affecting current period net income.  Fluctuations in the market value
of these instruments have no impact on cash flow until the instruments are
settled.
 
 Provident’s
commodity price risk management program utilizes derivative instruments to
provide insurance against lower commodity prices and margins.  The
program provides support for cash distributions, capital programs and bank
financing. The risk management strategy protects a percentage of
Provident’s oil and natural gas production against a decline in commodity prices
while, with some products, allowing the Trust to participate in a rising
commodity price environment. It provides price stabilization and protection of a
percentage of inventory values and fractionation spread margin associated with
the Midstream business unit.  As well, the Provident risk management
strategy reduces foreign exchange risk due to the exposure arising from the
conversion of U.S. dollars into Canadian dollars.
 
 Management
believes that financial markets currently provide adequate liquidity through
price discovery and active credit-worthy counterparties for Provident to
continue to execute the program in 2009.  The derivative instruments
the Trust uses include puts, calls, costless collars, participating swaps, and
fixed price products that settle against indexed referenced
pricing.
  
 Provident
Energy 2008 Management’s Discussion and Analysis
 - 22
-
 
 Provident’s
credit policy governs the activities undertaken to mitigate non-performance risk
by counterparties to financial derivative instruments.  Activities
undertaken include regular monitoring of counterparty exposure to approved
credit limits, financial reviews of all active counterparties, utilizing
International Swap Dealers Association (ISDA) agreements and obtaining financial
assurances where warranted.  In addition, Provident has a diversified
base of available counterparties.
 
 Disclosure
Controls and Procedures:  U.S. Sarbanes-Oxley Act
 
 In 2002,
the United States Congress enacted the Sarbanes-Oxley Act (SOX), which
stipulates that corporations publicly traded on U.S. financial exchanges must
assess the effectiveness of their internal controls over financial
reporting.  As a foreign filer listed on the New York Stock Exchange,
Provident is required to conduct the assessment.  See “Management’s
Report on Internal Control Over Financial Reporting” and “Independent Auditors’
Report”.
 
 Based on
their evaluation as of December 31, 2008, Provident’s chief executive officer
and chief financial officer concluded that Provident’s disclosure controls and
procedures (as defined in Rules 13(a)-15(e) and 15(d)-15(e) under the United
States Securities Exchange Act of 1934 (the Exchange Act) are effective to
ensure that information required to be disclosed by Provident in reports that it
files or submits under the Exchange Act is recorded, processed, summarized and
reported within the time periods specified in the United States Securities and
Exchange Commission rules and forms.  In addition, as of December 31,
2008, there were no changes in Provident’s internal controls over financial
reporting that occurred during 2008 that have materially affected, or are
reasonably likely to materially affect its internal controls over financial
reporting.
 
 Provident
will continue to periodically evaluate its disclosure controls and procedures
and internal controls over financial reporting and will make any modifications
from time to time as deemed necessary.
 
 The Trust
has undertaken a comprehensive review of the effectiveness of its internal
control over financial reporting as part of the reporting, certification and
attestation requirements of Section 404 of the U.S. Sarbanes-Oxley Act of
2002.  For the year ended December 31, 2008 the company’s internal
controls were found to be operating free of any material
weaknesses.
 
 Goodwill
 
 Goodwill
represents the excess of the cost of an acquired enterprise over the net of the
amounts assigned to assets acquired and liabilities assumed.  As at
December 31, 2007 Goodwill was comprised of $416.9 million related to
acquisitions in the Canadian oil and gas business and $100.4 million resulted
from the Midstream NGL Acquisition in 2005.
 
 Goodwill
is assessed for impairment at least annually, and if an impairment exists, it
would be charged to income in the period in which the impairment
occurs.  The impairment test includes a comparison of the net book
value of the Trust’s assets, by reporting units, to the estimated fair value of
the reporting unit.  In 2008, Provident engaged the services of a
third-party evaluator to assist in determining fair value.  Valuation
methodologies included discounted cash flow, a transaction-based approach and a
market-based approach, using trading multiples.  Goodwill is not
amortized.
 
 The Trust
performed its annual goodwill impairment test in the fourth quarter of 2008 and
determined that the fair value of the Canadian oil and gas production unit was
lower than the respective carrying value, primarily due to increasing economic
uncertainty in the global market and the resulting higher cost of capital
assumptions in the valuation methodologies.  Consequently, a goodwill
impairment, amounting to $416.9 million was recorded.  The impairment
test indicated that the fair value of the Midstream reporting unit was in excess
of the respective carrying value, therefore no write down of midstream-related
goodwill was required.    At December 31, 2008 the goodwill
balance of $100.4 million is related entirely to the Provident Midstream
reporting unit.
 
 
 Provident
Energy 2008 Management’s Discussion and Analysis
 - 23
-
 
 Liquidity
and capital resources
  Continuing
      operations
                
                As
      at December 31,($
      000s)
                
                2008
                
                
                2007
                
                
                %
      ChangeLong-term
      debt - revolving term credit facility
                
                $
                504,685
                
                
                $
                923,996
                
                
                
                (45
                )Long-term
      debt - convertible debentures (including current portion)
                
                
                260,994
                
                
                
                275,638
                
                
                
                (5
                )Working
      capital surplus(1)
                
                
                (39,041
                )
                
                
                (58,732
                )
                
                
                (34
                )Net
      debt
                
                $
                726,638
                
                
                $
                1,140,902
                
                
                
                (36
                )Unitholders'
      equity (at book value)
                
                
                1,636,347
                
                
                
                1,708,665
                
                
                
                (4
                )Total
      capitalization at book value
                
                $
                2,362,985
                
                
                $
                2,849,567
                
                
                
                (17
                )Total
      net debt as a percentage of total book value
capitalization
                
                
                31
                %
                
                
                40
                %
                
                
                (23
                )(1)
      The working capital surplus excludes balances for the current portion of
      financial derivative instruments.
 
 Provident
operates two business units with similar but not identical monthly cash
settlement cycles.  Midstream revenues are received at various times
throughout the month.  Provident’s working capital position is
affected by seasonal fluctuations that reflect commodity price changes, drilling
cycles in its oil and gas operations and inventory balances in its Midstream
business unit.  Provident relies on funds flow from operations,
external lines of credit and access to equity markets to fund capital programs
and acquisitions.
 
 As a
result of the weakening of the global economy, oil and gas industry
participants, including Provident, are experiencing more restricted access to
capital and anticipate increased borrowing costs.  Although
Provident’s business and asset base have not changed, the lending capacity of
financial institutions has been diminished and risk premiums have
increased.  Management continues to believe that cash flows from
operating activities and availability under existing bank facilities will be
adequate to allow Provident to move forward with its 2009 capital
program.  However, these issues will affect Provident as it reviews
financing alternatives for future capital expenditures and potential acquisition
opportunities in the current lower commodity price environment.
 
 Substantially
all of Provident's accounts receivable are due from customers and joint venture
partners in the oil and gas and midstream services and marketing industries and
are subject to credit risk. Provident partially mitigates associated credit risk
by limiting transactions with certain counterparties to limits imposed by
Provident based on management’s assessment of the creditworthiness of such
counterparties.  The carrying value of accounts receivable reflects
management's assessment of the associated credit risks.
 
 As at
December 31, 2008, Provident held non-bank sponsored asset-backed commercial
paper with a face value of $6.1 million.  Provident has recorded an
impairment write-down amounting to $4.3 million in 2008 (2007 - $1.8 million) to
reflect the fair value of these assets at December 31, 2008, determined to be
nil.  The write-down is included in net income as part of foreign
exchange (gain) loss and other.
 
 Contractual
obligations
  Consolidated
                
                Payment
      due by period($
      millions)
                
                Total
                
                
                Less
                  than
      1
                  year
                
                1
      to 3
                  years
                
                4
      to 5
                  years
                
                
                More
                  than
      5
                  yearsLong-term
      debt - revolving term credit facility (1)
      (3)
                
                $
                548.8
                
                
                $
                16.8
                
                $
                532.0
                
                $
                -
                
                
                $
                -Long-term
      debt - convertible debentures(2)
      (3)
                
                
                321.6
                
                
                
                42.5
                
                
                175.8
                
                
                103.3
                
                
                
                -Operating
      lease obligations
                
                
                195.6
                
                
                
                22.3
                
                
                37.6
                
                
                29.1
                
                
                
                106.6Total
                
                $
                1,066.0
                
                
                $
                81.6
                
                $
                745.4
                
                $
                132.4
                
                
                $
                106.6(1)
      The terms of the Canadian credit facility have a revolving three year
      period expiring on May 30, 2011.(2)
      Includes current portion of convertible debentures.(3)
      Includes associated interest and principal payments.
   Provident
Energy 2008 Management’s Discussion and Analysis
 - 24
-
 
 Long-term
debt and working capital
 
 As at
December 31, 2008 Provident had drawn on 45 percent of its term credit facility
of $1,125 million as compared to 81 percent drawn as at December 31,
2007.  The decrease in the level of bank debt reflects the application
of $457.9 million of cash proceeds, net of tax, realized on the disposition of
USOGP.  During 2008, capital expenditures and distributions to
unitholders were roughly equivalent with the sum of funds flow from operations,
DRIP proceeds and changes in working capital.
 
 At
December 31, 2008 Provident had letters of credit guaranteeing Provident’s
performance under certain commercial and other contracts that totaled $35.2
million, increasing bank line utilization to 48 percent.  The
guarantees at December 31, 2007 totaled $31.6 million.
 
 Provident’s
working capital from continuing operations increased by $106.6 million from a
deficit of $89.4 million to a surplus of $17.2 million as at December 31,
2008.  The significant increase is primarily due to a $132.0 million
decrease in net current financial derivative instrument liabilities, a $103.2
million decrease in accounts payable and accrued liabilities, partially offset
by decreased accounts receivable of $93.6 million and a $38.5 million decrease
in inventory.
 
 The ratio
of net debt (as calculated under “Liquidity and capital resources”) to funds
flow from continuing operations in 2008 was 1.4 to one, compared to 3.0 to one
in 2007.  The decrease reflects a decrease in net debt as well as
higher funds flow from operations.  On a segmented basis, the
Provident Upstream business had a ratio of net debt to funds flow from
operations in 2008 of 0.7 to one (2007 – 1.8 to one).  The ratio for
the Provident Midstream business unit was 2.7 to one in 2008, compared to 4.3 to
one in 2007.
 
 Trust
units
 
 For the
year ended December 31, 2008 the Trust issued six thousand units on conversion
of convertible debentures (2007 – 0.5 million units).  An additional
0.2 million units were issued pursuant to the unit option plan for the year
ended December 31, 2008 (2007 – 0.8 million units).  Under Provident’s
Premium Distribution, Distribution Reinvestment (DRIP) and Optional Unit
Purchase Plan program 6.3 million units were issued or are to be issued in 2008
representing proceeds of $53.8 million (2007 – 4.5 million units for proceeds of
$50.5 million).
 
 At
December 31, 2008 management and directors held less than one percent of the
outstanding trust units.
 
 Capital
expenditures and funding
 
 Continuing
      operations
                
                Year
      ended December 31,($
      000s)
                
                2008
                
                
                2007
                
                
                %
      ChangeCapital
      ExpendituresCapital
      expenditures and site restoration expenditures
                
                $
                (253,328
                )
                
                $
                (182,175
                )
                
                
                39Property
      acquisitions, net
                
                
                (24,181
                )
                
                
                (13,050
                )Corporate
      acquisitions
                
                
                -
                
                
                
                (469,795
                )Net
      capital expenditures
                
                $
                (277,509
                )
                
                $
                (665,020
                )
                
                
                (58
                )Funded
      ByFunds
      flow from continuing operations net of declared
                  distributions
      to unitholders
                
                $
                165,331
                
                
                $
                49,332
                
                
                
                235Proceeds
      on sale of discontinued operations, net of tax
                
                
                457,906
                
                
                
                -
                
                
                
                -(Decrease)
      increase in long-term debt
                
                
                (440,244
                )
                
                
                169,122
                
                
                
                -Issue
      of trust units, net of cost; excluding DRIP
                
                
                1,672
                
                
                
                362,418
                
                
                
                (100
                )DRIP
      proceeds
                
                
                53,838
                
                
                
                50,491
                
                
                
                7Change
      in working capital, including cash,
                  sale
      of assets and change in investments
                
                
                39,006
                
                
                
                33,657
                
                
                
                16Net
      capital expenditure funding
                
                $
                277,509
                
                
                $
                665,020
                
                
                
                (58
                )
   Provident
Energy 2008 Management’s Discussion and Analysis
 - 25
-
 
 Net
capital expenditures were funded by a combination of funds flow from operations,
debt, equity issued from treasury through public offerings, the DRIP program and
proceeds on the sale of discontinued operations.
 
 Non-cash
unit based compensation
  Non-cash
unit based compensation includes expenses or recoveries associated with
Provident’s restricted and performance unit plan as well as the unit option
plan.  Provident accounts for the unit option plan using the fair
value of the option at the time of issue.  The other unit based
compensation is recorded at the estimated fair value of the notional units
granted.  Compensation expense associated with the plans is recognized
in earnings over the vesting period of each plan.  The expense or
recovery associated with each period is recorded as non-cash unit based
compensation (a component of general and administrative expense).  A
portion relating to operational employees at field and plant locations is also
allocated to operating expense.  For the year ended December 31, 2008,
Provident recorded unit based compensation expense of $4.4 million (2007 - $10.2
million) and made related cash payments of $8.3 million (2007 - $1.8
million).  The expense is lower in 2008 as a result of a lower
Provident trust unit trading price, upon which the compensation is
based.  At December 31, 2008, the current portion of the liability
totaled $9.4 million (December 31, 2007 - $9.9 million) and the long-term
portion totaled $8.6 million (December 31, 2007 - $12.4 million).
    Provident
Energy 2008 Management’s Discussion and Analysis
 - 26
-
 
 Provident
Upstream segment review
 
 Crude
oil and natural gas liquids prices
  Provident
      Upstream
                
                Year
      ended December 31,($
      per bbl)
                
                2008
                
                
                2007
                
                
                %
      ChangeOil
      per barrelWTI
      (US$)
                
                $
                99.65
                
                
                $
                72.31
                
                
                
                38Exchange
      rate (from US$ to Cdn$)
                
                $
                1.07
                
                
                $
                1.07
                
                
                
                -WTI
      expressed in Cdn$
                
                $
                106.33
                
                
                $
                77.67
                
                
                
                37Realized
      pricing before financial derivative instrumentsCrude
      oil
                
                $
                82.79
                
                
                $
                56.74
                
                
                
                46Natural
      gas liquids
                
                $
                76.88
                
                
                $
                55.07
                
                
                
                40Crude
      oil and natural gas liquids
                
                $
                82.27
                
                
                $
                56.54
                
                
                
                46
  The above
realized prices are net of transportation expense.
 
 For the
year ended December 31, 2008 Provident’s realized crude oil and natural gas
liquids price, prior to the impact of financial derivative instruments,
increased by 46 percent to average $82.27 compared to $56.54 in
2007.  The 2008 increase related to a 38 percent higher US$ WTI crude
oil price and narrower pricing differentials on crude oil streams.
 
 Natural
gas price
  Provident
      Upstream
                
                Year
      ended December 31,($
      per mcf)
                
                2008
                
                
                2007
                
                
                %
      ChangeAECO
      monthly index (Cdn$ per mcf)
                
                $
                8.12
                
                
                $
                6.59
                
                
                
                23Corporate
      natural gas price per mcf before financialderivative
      instruments (Cdn$)
                
                $
                8.23
                
                
                $
                6.42
                
                
                
                28
  The above
prices are net of transportation expense.
 
 For the
year ended December 31, 2008 Provident’s realized natural gas price, excluding
financial derivative instruments, increased 28 percent as compared to 2007,
greater than the increase in the benchmark AECO monthly index
price.  Provident’s gas portfolio includes aggregator contracts sold
on a term basis that can differ from the benchmark price and sells to the spot
market on monthly or daily indices and receives prices which take into account
heat content.  Provident’s realized prices and changes in prices can
therefore differ from benchmark indices.
 
 Production
  Provident
      Upstream
                
                Year
      ended December 31,2008
                
                
                2007
                
                
                %
      ChangeDaily
      productionCrude
      oil (bpd)
                
                
                12,473
                
                
                
                9,797
                
                
                
                27Natural
      gas liquids (bpd)
                
                
                1,203
                
                
                
                1,316
                
                
                
                (9
                )Natural
      gas (mcfd)
                
                
                84,039
                
                
                
                92,378
                
                
                
                (9
                )Oil
      equivalent (boed) (1)
                
                
                27,683
                
                
                
                26,509
                
                
                
                4(1)
      Provident reports equivalent production converting natural gas to oil on a
      6:1 basis.
   Provident
Energy 2008 Management’s Discussion and Analysis
 - 27
-
 
 For the
year ended December 31, 2008, Provident Upstream production averaged 27,683
boed, a four percent increase compared to 26,509 boed in 2007.  The
increase is primarily a result of the full year effect in 2008 of the two
acquisitions, Capitol in June of 2007 and Triwest in December of 2007, the
additional working interests acquired throughout 2008, and the production
volumes added through drilling and optimization activities, partially offset by
production declines typical in the Western Canadian Sedimentary
Basin.  The Capitol acquisition became Provident Upstream’s newest
core area, Dixonville, and the Triwest acquisition is included in the Southeast
Saskatchewan core area.
 
 Production
for 2008 was weighted 51 percent natural gas and 49 percent crude oil and
natural gas liquids.  This compared to 2007 production weighted 58
percent natural gas and 42 percent crude oil and natural gas
liquids.  Year-over-year, the change in mix reflects the full year
effect for 2008 of the two acquisitions in 2007 which were primarily
light/medium crude oil production.
 
 Provident
Upstream production summarized by core areas is as follows:
  Year
      ended December 31,Provident
      Upstream
                
                2008
                
                
                2007
                
                
                %
      ChangeDaily
      Production - by area (boed) (1)West
      Central Alberta
                
                
                6,271
                
                
                
                7,011
                
                
                
                (11
                )Southern
      Alberta
                
                
                4,883
                
                
                
                5,622
                
                
                
                (13
                )Northwest
      Alberta
                
                
                4,690
                
                
                
                4,905
                
                
                
                (4
                )Dixonville(2)
                
                
                3,764
                
                
                
                2,058
                
                
                
                83Southeast
      Saskatchewan
                
                
                3,061
                
                
                
                1,769
                
                
                
                73Southwest
      Saskatchewan
                
                
                1,333
                
                
                
                1,726
                
                
                
                (23
                )Lloydminster
                
                
                3,681
                
                
                
                3,418
                
                
                
                827,683
                
                
                
                26,509
                
                
                
                4(1)
      Provident reports equivalent production converting natural gas to oil on a
      6:1 basis.(2)
      Dixonville production in 2007 represents production from June 19, 2007
      (date of Capitol Energy Resources Ltd. acquisition)amounting
      to 3,852 boed for the 195 days.
   Provident
Energy 2008 Management’s Discussion and Analysis
 - 28
-
 
 Revenue
and royalties
  Provident
      Upstream
                
                Year
      ended December 31,($
      000s except per boe and mcf data)
                
                2008
                
                
                2007
                
                
                %ChangeOilRevenue
                
                $
                377,976
                
                
                $
                202,909
                
                
                
                86Realized
      loss on financial derivative instruments
                
                
                (11,113
                )
                
                
                (7,905
                )
                
                
                41Royalties
                
                
                (69,897
                )
                
                
                (39,211
                )
                
                
                78Net
      revenue
                
                $
                296,966
                
                
                $
                155,793
                
                
                
                91Net
      revenue (per barrel)
                
                $
                65.05
                
                
                $
                43.57
                
                
                
                49Royalties
      as a percentage of revenue
                
                
                18.5
                %
                
                
                19.3
                %Natural
      gasRevenue
                
                $
                253,183
                
                
                $
                216,626
                
                
                
                17Realized
      gain on financial derivative instruments
                
                
                11
                
                
                
                9,633
                
                
                
                (100
                )Royalties
                
                
                (44,715
                )
                
                
                (41,154
                )
                
                
                9Net
      revenue
                
                $
                208,479
                
                
                $
                185,105
                
                
                
                13Net
      revenue (per mcf)
                
                $
                6.78
                
                
                $
                5.49
                
                
                
                23Royalties
      as a percentage of revenue
                
                
                17.7
                %
                
                
                19.0
                %Natural
      gas liquidsRevenue
                
                $
                33,857
                
                
                $
                26,451
                
                
                
                28Royalties
                
                
                (8,528
                )
                
                
                (6,681
                )
                
                
                28Net
      revenue
                
                $
                25,329
                
                
                $
                19,770
                
                
                
                28Net
      revenue (per barrel)
                
                $
                57.53
                
                
                $
                41.16
                
                
                
                40Royalties
      as a percentage of revenue
                
                
                25.2
                %
                
                
                25.3
                %TotalRevenue
                
                $
                665,016
                
                
                $
                445,986
                
                
                
                49Realized
      (loss) gain on financial derivative instruments
                
                
                (11,102
                )
                
                
                1,728
                
                
                
                -Royalties
                
                
                (123,140
                )
                
                
                (87,046
                )
                
                
                41Net
      revenue
                
                $
                530,774
                
                
                $
                360,668
                
                
                
                47Net
      revenue (per boe)
                
                $
                52.39
                
                
                $
                37.27
                
                
                
                41Royalties
      as a percentage of revenue
                
                
                18.5
                %
                
                
                19.5
                %Note: the
      above revenue, net revenue and net revenue per boe figures are presented
      net of transportation expenses.
  For the
year ended December 31, 2008 Provident Upstream production revenue was $665.0
million, an increase of 49 percent from $446.0 million in 2007.  The
increase in revenue was a result of the four percent increase in production and
higher realized crude oil, natural gas liquids, and natural gas
prices.  Royalties as a percentage of revenue had a slight decrease to
18.5 percent reflecting capital expenditures on gas facilities.  The
preceding factors offset by the $11.1 million realized loss on financial
derivative instruments compared to a $1.7 million realized gain in 2007, account
for net revenue of $530.8 million in 2008, 47 percent higher than the $360.7
million recorded in 2007.
 
 Net
revenue per boe in 2008 increased 41 percent to $52.39 from $37.27 in 2007
resulting primarily from higher realized crude oil, natural gas liquids, and
natural gas prices and a higher percentage of production from crude oil and
natural gas liquids.
   Provident
Energy 2008 Management’s Discussion and Analysis
 - 29
-
 
 Production
expense
  Provident
      Upstream
                
                Year
      ended December 31,($
      000s, except per boe data)
                
                2008
                
                
                2007
                
                
                %
      ChangeProduction
      expenses
                
                $
                138,173
                
                
                $
                112,387
                
                
                
                23Production
      expenses (per boe)
                
                $
                13.64
                
                
                $
                11.62
                
                
                
                17
  For the
year ended December 31, 2008 production expenses increased 23 percent to $138.2
million from $112.4 million and increased by 17 percent on a per boe basis to
$13.64 per boe from $11.62 per boe in the prior year.  The increase in
total costs was due to the four percent increase in production combined with
returning higher operating cost wells to production in the second and third
quarters of 2008 to take advantage of record crude oil prices and associated
netbacks.  The increased commodity prices resulted in high prices for
fuel and power and high industry activity levels in the second and third
quarters of 2008 resulted in increased costs for service related activities for
down-hole and maintenance work.  The wells returned to production
included higher operating costs for fluid hauling, and associated maintenance
and down-hole costs.  In addition, colder weather in the first and
fourth quarters of 2008 impacted operations and unscheduled turnarounds in
Northwest Alberta were performed in the fourth quarter of 2008 to take advantage
of circumstances resulting from a third-party pipeline outage.
 
 Operating
netback
  Provident
      Upstream
                
                Year
      ended December 31,($
      per boe)
                
                2008
                
                
                2007
                
                
                %
      ChangeNetback
      per boeGross
      production revenue
                
                $
                65.64
                
                
                $
                46.09
                
                
                
                42Royalties
                
                
                (12.15
                )
                
                
                (9.00
                )
                
                
                35Operating
      costs
                
                
                (13.64
                )
                
                
                (11.62
                )
                
                
                17Field
      operating netback
                
                
                39.85
                
                
                
                25.47
                
                
                
                56Realized
      (loss) gain on financial derivative instruments
                
                
                (1.10
                )
                
                
                0.18
                
                
                
                -Operating
      netback after realized financial derivative instruments
                
                $
                38.75
                
                
                $
                25.65
                
                
                
                51
  Provident
Upstream operating netbacks have transportation expense netted against gross
production revenue.
 
 The 2008
field operating netback of $39.85 per boe was 56 percent above the $25.47 per
boe for the prior year.  This reflects increased realized crude oil,
natural gas liquids, and natural gas prices and an increase in Provident’s
production mix of crude oil and natural gas liquids to 49 percent in 2008 from
42 percent in 2007.  This was partially offset by 17 percent higher
operating costs per boe.  Royalties, which are price sensitive,
increased by 35 percent on a boe basis reflecting the higher commodity
prices.  The 2008 operating netbacks after financial derivative
instruments increased by 51 percent to $38.75 from $25.65 in the prior year due
to the preceding factors as well as the realized loss on financial derivative
instruments of $1.10 per boe compared to $0.18 per boe realized gain in the
prior year.
 
 General
and administrative
  Provident
      Upstream
                
                Year
      ended December 31,($
      000s, except per boe data)
                
                2008
                
                
                2007
                
                
                %
      ChangeCash
      general and administrative
                
                $
                36,191
                
                
                $
                27,102
                
                
                
                34Non-cash
      unit based compensation
                
                
                (2,199
                )
                
                
                3,698
                
                
                
                -$
                33,992
                
                
                $
                30,800
                
                
                
                10Cash
      general and administrative (per boe)
                
                $
                3.57
                
                
                $
                2.80
                
                
                
                28
   Provident
Energy 2008 Management’s Discussion and Analysis
 - 30
-
 
 For the
year ended December 31, 2008, cash general and administrative expenses were
$36.2 million (2007 - $27.1 million), an increase of 34 percent.  On a
boe basis, cash general and administrative expenses in 2008 increased 28 percent
to $3.57 per boe from $2.80 per boe in 2007.  The 2008 cash general
and administrative expenses included $4.5 million, or $0.45 per boe (2007 - $0.9
million or $0.09 per boe) related to payments associated with unit based
compensation.  The unit based expense was accrued over a three-year
vesting period as non-cash unit based compensation, consequently, there is an
offsetting reduction in non-cash unit based compensation when the payments are
made.  Excluding these payments, cash general and administrative
expenses were $31.7 million, or $3.12 per boe (2007 - $26.2 million or $2.71 per
boe).  The increase reflects higher office-related expenses,
particularly rent, and costs associated with the previously announced strategic
evaluation of Provident’s business units, including an internal structural
reorganization completed in the fourth quarter of 2008.
 
 Non-cash
unit based compensation was a recovery of $2.2 million in 2008 and an expense of
$3.7 million in 2007.  Excluding the related cash payments in each
year, non-cash unit based compensation was an expense of $2.3 million in 2008
(2007 - $4.6 million).  Non-cash unit based compensation is lower in
2008 as a result of a lower Provident trust unit trading price, upon which the
compensation is based.
 
 Capital
expenditures
  Provident
      Upstream
                
                Year
      ended December 31,($
      000s)
                
                2008
                
                
                2007Capital
      expenditures - by categoryGeological,
      geophysical and land
                
                $
                25,474
                
                
                $
                4,519Drilling
      and recompletions
                
                
                146,992
                
                
                
                113,425Facilities
      and equipment
                
                
                34,514
                
                
                
                13,378Office
      and other
                
                
                2,167
                
                
                
                14,887Total
      additions
                
                $
                209,147
                
                
                $
                146,209Capital
      expenditures - by areaWest
      central Alberta
                
                $
                10,326
                
                
                $
                9,051Southern
      Alberta
                
                
                19,852
                
                
                
                13,079Northwest
      Alberta
                
                
                79,445
                
                
                
                35,993Dixonville
                
                
                60,339
                
                
                
                43,801Southeast
      Saskatchewan
                
                
                21,175
                
                
                
                5,069Southwest
      Saskatchewan
                
                
                5,369
                
                
                
                15,196Lloydminster
                
                
                8,181
                
                
                
                9,235Other
                
                
                4,460
                
                
                
                14,785Total
      additions
                
                $
                209,147
                
                
                $
                146,209Property
      acquisitions, net
                
                $
                24,181
                
                
                $
                13,050
 
 In 2008,
Provident’s Upstream business unit spent $207.0 million on capital expenditures
before office and other capital costs.  Internal development
activities included 87.4 net wells drilled for the year ended December 31, 2008
with a 99 percent success rate.  Provident’s drilling activities in
2008 were more focused on crude oil compared to 2007.  Provident spent
$79.4 million in Northwest Alberta, primarily on drilling and completion
activities which included 14.0 net wells drilled, the infrastructure and tie-in
activities associated with the 2007/2008 winter drilling program and preparation
work to start the 2008/2009 winter drilling program.  Facility and
pipeline work in Northwest Alberta included preparation work to develop the
emerging Pekisko opportunity and 95.4 net sections (approximately 61,000 acres)
of land were also acquired for the Pekisko opportunity.  Provident
spent $60.3 million in the newest core area, Dixonville, primarily on drilling
and completion activities which resulted in 41.0 net wells
drilled.  In the Southeast Saskatchewan core area, $21.2 million was
spent which included 13.8 net wells drilled.  As oil prices increased
during the first half of 2008, capital work was primarily focused on oil
drilling in Dixonville and primarily light oil drilling in Southeast
Saskatchewan.  The shallow gas drilling program in Southwest
Saskatchewan was reduced.  In Southern Alberta, $19.9 million was
primarily spent on drilling activity and recompletions, which included 14.1 net
wells drilled, and on facility upgrades and infrastructure work.  The
$26.2
 
 Provident
Energy 2008 Management’s Discussion and Analysis
 - 31
-
 
 million
of capital spent in the remaining core areas included drilling, completion,
tie-ins, recompletions, facility upgrades and production optimization
activities.
 
 Additions
to proved plus probable reserves (before revisions) through internal capital
replaced approximately 70 percent of annual production.
 
 In 2008,
Provident also spent $24.2 million on property acquisitions primarily on
acquiring additional working interests in Northwest Alberta and Southern
Alberta.
 
 Depletion,
depreciation and accretion (DD&A)
  Provident
      Upstream
                
                Year
      ended December 31,($
      000s, except per boe data)
                
                2008
                
                
                2007
                
                
                %
      ChangeDD&A
                
                $
                304,909
                
                
                $
                256,723
                
                
                
                19DD&A
      (per boe)
                
                $
                30.09
                
                
                $
                26.53
                
                
                
                13
  The
Provident Upstream DD&A rate of $30.09 per boe increased 13 percent for 2008
compared to $26.53 per boe in 2007.  The increase was partly as a
result of the two acquisitions of Capitol and Triwest in 2007.  In
addition, 2008 expenditures on geological, geophysical, land and facilities
added to costs to be depleted without directly adding proved
reserves.  The recent Upstream acquisitions and the Rainbow assets
acquired in 2006 differed from earlier acquisitions in that they included
significant reserves that were not yet proved.  Since depletion
calculations are based on proved reserves, acquisitions with unproved reserves
generally result in higher depletion rates.  The impact of this,
combined with the higher cost of acquiring or drilling proved reserves in
western Canada in an environment with higher commodity prices and increased
drilling costs, will be reflected in the DD&A rate going
forward.
 
 In 2008,
DD&A also includes accretion expense associated with asset retirement
obligation of $3.4 million (2007 - $2.5 million).
 
 As part
of the reconciliation of Provident’s financial statements to United States
generally accepted accounting principles (U.S. GAAP), disclosed in note 18 to
the consolidated financial statements, the Trust has reflected additional
depletion in 2008 of $814.0 million (2007 – $181.6 million) and a related future
income tax recovery of $214.3 million (2007 - $52.2 million) as a result of the
application of the U.S. GAAP ceiling test.  These charges were not
required under Canadian generally accepted accounting principles.
 
 
 Provident
Energy 2008 Management’s Discussion and Analysis
 - 32
-
 
 Provident
Midstream business segment review
  The
Midstream business
 
 The
Midstream business unit extracts, processes, stores, transports and markets
natural gas liquids (NGL) for Provident and offers these services to third party
customers.  The Provident Midstream segment contains three business
lines:
  Empress
East
 Redwater
West
 Commercial
Services
 
 The
Empress East business line is comprised of the following core
assets:
 
 ·
              Approximately
      2.0 Bcfd of extraction capacity at Empress, Alberta.  This is
      the combination of 67.5 percent ownership of the 1.2 Bcfd capacity
      Provident Empress NGL extraction plant, 12.4 percent ownership in the 1.1
      Bcfd capacity ATCO Plant, 8.3 percent ownership in the 2.4 Bcfd capacity
      Spectra Plant and 33.0 percent ownership in the 2.7 Bcfd capacity BP
      Empress 1 Plant.
 
 ·
              100
      percent ownership of a 50,000 bpd debutanizer at Empress,
      Alberta.
 
 ·
              50
      percent ownership in the 130,000 bpd Kerrobert pipeline and 2.5 mmbbl
      underground storage facility near Kerrobert, Saskatchewan which
      facilitates injection into the Enbridge pipeline system.  Along
      the Enbridge pipeline system in Superior, Wisconsin, Provident holds an
      18.3 percent ownership of a 300,000 barrel storage staging facility and
      18.3 percent ownership of the 6,600 bpd
  depropanizer.
 
 ·
              In
      Sarnia, Ontario, 10.3 percent ownership of an approximately 150,000 bpd
      fractionator, 1.7 mmbbl of raw product storage capacity and 18 percent of
      5.0 mmbbl of finished product storage and rail, truck and pipeline
      terminalling.  An additional 0.5 mmbbls of specification product
      storage is also available in the Sarnia
area.
 
 ·
              A
      propane distribution terminal at Lynchburg,
  Virginia.
 
 ·
              A
      rail car fleet of approximately 300 rail cars under long-term lease
      agreement.
 
 The
Redwater West business line is comprised of the following core
assets:
 
 ·
              100
      percent ownership of the Redwater NGL fractionation facility,
      incorporating a 65,000 bpd fractionation, storage and transportation
      facility that includes 12 pipeline receipt and delivery points, railcar
      loading facilities with direct access to CN rail and indirect access to CP
      rail, two propane truck loading facilities, six million gross barrels of
      salt cavern storage, and a 60,000 bpd condensate rail offloading facility
      with a 300 railcar storage yard.  The facility can process
      high-sulphur NGL streams and is one of only two ethane-plus fractionation
      facilities in western Canada capable of extracting ethane from the natural
      gas liquids stream.
 
 ·
              In
      2009, two new caverns (approximately 500,000 barrels each) will be brought
      into service and are planned to be used for condensate
      storage.
 
 ·
              Approximately
      7,000 bpd of leased fractionation capacity at other
      facilities.
 
 ·
              43.3
      percent direct ownership and 100 percent control of all products from the
      38,500 bpd Younger NGL extraction plant located at Taylor in northeastern
      British Columbia. The Younger plant supplies local markets as well as
      Provident’s Redwater fractionation facility near
  Edmonton.
 
 ·
              100
      percent ownership of the 565 kilometer proprietary Liquids Gathering
      System (“LGS”) that runs along the Alberta-British Columbia border
      providing access to a highly active basin for liquids-rich natural gas
      exploration and exploitation.  Provident also has long-term
      shipping rights on the Pembina pipeline system that extends the product
      delivery transportation network through to the Redwater fractionation
      facility.
   Provident
Energy 2008 Management’s Discussion and Analysis
 - 33
-
  ·
              A
      rail car fleet of approximately 700 rail cars under long-term lease
      agreement.
 
 The
Commercial Services business line:
 
 The
Commercial Services business line includes services such as fractionation,
storage, and loading at Provident’s Redwater facility on a fee
basis.  It also includes pipeline tariff income from Provident’s
ownership of the Liquids Gathering System in Northwest Alberta which flows into
Pembina’s pipeline from LaGlace to Redwater.  Provident also collects
tariff income from its 50 percent ownership in the Kerrobert Pipeline which
transports NGLs from Empress to Kerrobert for injection into the Enbridge
pipeline for delivery to Sarnia.  Provident owns a debutanizer at its
Empress facility, which removes condensate from the NGL mix for sale as a
diluent to blend with heavy oil. This service is provided to a major energy
company on a long term cost of service basis.  Earnings from this
business line of the Midstream segment have little direct exposure to market
prices volatility and are thus relatively stable.
 
 Long
term contracts
 
 At the
Redwater fractionation facility, a significant portion of the available propane
plus fractionation capacity is contracted through a long term fee for service
arrangement with third parties.
 
 In 2006
and early 2007, Provident commissioned a 60,000 bpd condensate rail off-loading
terminal at Redwater, a significant portion of which is under long term
contracts with two major energy producers.
 
 The
ethane produced from Provident’s facilities at Empress and Redwater is largely
sold under long term contracts.
 
 Provident
has a long term contract on a cost of service basis for the majority of its
50,000 bbl/d Empress debutanizer facility.  Provident also has a long
term contract for 500,000 barrels of specification product storage in the Sarnia
area.
 
 The 2008
Provident Midstream business unit results can be summarized as
follows:
  Year
      ended December 31,($
      000s)
                
                2008
                
                
                2007
                
                
                %
      ChangeEmpress
      East Margin
                
                $
                157,976
                
                
                $
                183,565
                
                
                
                (14
                )Redwater
      West Margin
                
                
                142,836
                
                
                
                94,600
                
                
                
                51Commercial
      Services Margin
                
                
                46,541
                
                
                
                54,649
                
                
                
                (15
                )Gross
      operating margin
                
                
                347,353
                
                
                
                332,814
                
                
                
                4Realized
      loss on financial derivative instruments
                
                
                (118,917
                )
                
                
                (74,474
                )
                
                
                60Cash
      general and administrative expenses
                
                
                (35,528
                )
                
                
                (28,669
                )
                
                
                24Foreign
      exchange gain (loss) and other
                
                
                19,853
                
                
                
                (3,996
                )
                
                
                -Provident
      Midstream EBITDA
                
                $
                212,761
                
                
                $
                225,675
                
                
                
                (6
                )
 
 Gross
operating margin
 
 The
Empress East business line extracts NGLs from natural gas at the Empress
straddle plants and sells finished products into markets in Central Canada and
the Eastern United States. The margin in this business is determined primarily
by the “frac spread ratio”, which is the ratio between crude oil prices and
natural gas prices. The higher the ratio, the better this business line will
perform.  There is also a differential between propane, butane and
condensate (collectively, these products are referred to as “propane-plus”)
prices and crude oil prices which can change prices received and margins
realized for Midstream products separate from frac spread ratio
changes.  Operating margins reflect the prices realized on sale of
these products less the weighted average cost of purchasing, fractionating,
storing and transporting the products.  The business is seasonal and
carries inventory that generally builds over the second and third quarters of
the year and is sold in the fourth quarter and the first quarter of the
following year.
  
 Provident
Energy 2008 Management’s Discussion and Analysis
 - 34
-
 
 
 The 2008
gross operating margin from Empress East was $158.0 million compared to $183.6
million in 2007.  The decrease reflects approximately 18 percent
higher propane-plus prices offset by 29 percent higher propane-plus costs as a
result of a significant increase in gas prices in 2008.  Frac spread
ratios during the first nine months of 2008 averaged 14.3, compared to 11.6
during the same period in 2007.  However, frac spread ratios reversed
in the fourth quarter of 2008 averaging 11.2, compared to 15.7 during the fourth
quarter of 2007.  In addition, 2008 experienced a significant decline
in the sales price of propane relative to the price of crude
oil.  Posted prices at Mont Belvieu for propane in 2008 averaged 60
percent of WTI, compared to 70 percent in 2007.  Overall strong
performance in the first three quarters of 2008 was offset in the fourth quarter
by higher cost inventory built up in the second and third quarters at
historically high product prices, then subsequently sold in the fourth quarter,
when product prices had dropped significantly.
 
 Subsequent
to year end, conditions have shown some improvement.  The frac spread
ratio in January 2009 has improved by nine percent compared to December, and the
price of propane as a percentage of WTI has increased to 72
percent.
 
 The
Redwater West business line purchases an NGL mix from various producers and
fractionates it into finished products at the Redwater fractionation facility
near Edmonton, Alberta.  Because the feedstock for this business line
is primarily NGL mix rather than natural gas, the frac spread ratio has a
smaller impact on margin than in the Empress East business line.  This
facility also has the largest rail rack in Western Canada to receive products
for delivery into the local condensate market.  Provident has
considerably increased its participation in the condensate market over the past
year, reflecting the increased demand for condensate as diluent for heavy oil
production.
 
 In 2008,
the operating margin for the Redwater West business line was $142.8 million
(2007 - $94.6 million).  The 51 percent increase in margin was driven
by a 15 percent increase in propane-plus sales volumes, primarily condensate,
and a 26 percent increase in propane-plus prices versus a 25 percent increase in
costs.
 
 The
Commercial Services business line generates income from stable fee-for-service
contracts to provide fractionation, storage, loading, and marketing services to
upstream producers.  Income from pipeline tariffs from Provident’s
ownership in NGL pipelines is also included in this business line.  In
2008, the margin for this business line was $46.5 million (2007 - $54.6
million).  In 2008, while the margin for this business line was 15
percent lower, it does include a 46 percent increase in fees associated with our
offloading terminal, due to increased condensate business.  In 2007,
the Commercial Services margin included payments received for product quality
adjustments at our condensate offloading facility.  These payments
increased operating margin in 2007, are generally non-recurring and account for
the year over year decrease in operating margin.
 
 Operations
– Provident Midstream NGL sales volumes
 
 Provident
Midstream sold 119,649 bpd in 2008, compared with 120,785 in
2007.  Higher propane-plus volumes were offset by lower ethane volumes
reflecting reduced demand in the fourth quarter of 2008.
 
 Earnings before interest, taxes,
depletion, depreciation, accretion, and other non-cash items (“EBITDA”)
and funds flow from
operations
 
 For 2008,
Provident Midstream EBITDA decreased $12.9 million or six percent from $225.7
million in 2007.  A $14.5 million increase in gross operating margin
as described above, as well as foreign exchange gains on U.S. dollar-based
transactions, were tempered by a $44.4 million increase in realized losses on
financial derivative instruments and higher cash general and administrative and
other costs.  Funds flow from operations for 2008 was $179.0 million,
an increase of $0.6 million above the $178.4 million in 2007.  The
increase in funds flow from operations reflects the lower EBITDA being more than
offset by reduced interest charges and a current tax recovery.
 
 Cash
general and administrative expenses and other were $35.5 million for 2008 (2007-
$28.7 million).  Included in this amount is $3.8 million (2007 - $0.9
million) related to payments associated with unit based
compensation.  The expense was accrued over a three-year vesting
period as non-cash unit based compensation, consequently there is an offsetting
reduction in non-cash unit based compensation when the payments are
made.  Excluding these payments, cash general and administrative
expenses were $31.7 million in 2008 (2007 - $27.8 million).  The
increase reflects
   Provident
Energy 2008 Management’s Discussion and Analysis
 - 35
-
 
 higher
office-related expenses, particularly rent, and costs associated with the
previously announced strategic evaluation of Provident’s business units,
including an internal structural reorganization completed in the fourth quarter
of 2008.
 
 Management
uses EBITDA to analyze the operating performance of the Midstream business
unit.  EBITDA as presented does not have any standardized meaning
prescribed by Canadian GAAP and therefore it may not be comparable with the
calculation of similar measures for other entities. EBITDA as presented is not
intended to represent operating cash flow from operations or operating profits
for the period nor should it be viewed as an alternative to cash flow from
operations from operating activities, net earnings or other measures of
financial performance calculated in accordance with Canadian
GAAP.  All references to EBITDA throughout this report are based on
earnings before interest, taxes, depletion, depreciation, accretion, and other
non-cash items (“EBITDA”).
 
 Capital
expenditures
 
 Provident
Midstream capital expenditures in 2008 totaled $37.8 million.  In
2008, $20.8 million was spent on continued development of cavern storage, the
condensate offloading and terminalling facility, and expansion to the recently
completed truck loading facilities.  In addition, $7.7 million was
added to capitalized line-fill, $8.2 million was spent on sustaining capital
requirements and $1.1 million was spent primarily on development of systems to
improve information flow within the business unit.
   Discontinued
operations (USOGP)
  In
February 2008, the Trust announced a strategic process respecting the decision
to sell the operations that comprise the United States oil and natural gas
production (USOGP) business.  This business was comprised of
approximately 22 percent ownership of BreitBurn Energy Partners, L.P., a
publicly-traded U.S. Master Limited Partnership (“the MLP”).  This MLP
ownership also included units held by the General Partner of which Provident
owned approximately 96 percent.  In addition, Provident owned
approximately 96 percent of privately held BreitBurn Energy Company L.P.
(“BreitBurn”) which operates assets in California.
 
 Effective
in the first quarter of 2008, the USOGP business was accounted for as
discontinued operations.  Discontinued operations (USOGP) includes the
consolidated results of 100 percent of the MLP and
BreitBurn.  Non-controlling interests are comprised mainly of the
public ownership in the MLP, and to a lesser extent the ownership interests of
the managers in the MLP and BreitBurn, as well as third party investment in
USOGP’s land development project, which commenced in 2006.
 
 In June
2008, the Trust sold a portion of the USOGP business, consisting of its 22
percent interest in BreitBurn Energy Partners, L.P. (MLP) and its 96 percent
interest in BreitBurn GP LLC, for cash proceeds, net of transaction costs, of
U.S. $342.2 million.  The Trust has recorded a gain on sale of $187.9
million and $127.7 million in current tax expense related to this
transaction.  Also recorded was a realized foreign exchange loss of
$30.3 million, representing the recognition of the related portion of the
foreign exchange loss in accumulated other comprehensive income, which was
generated since inception in 2006.  These amounts are recorded as part
of net income from discontinued operations for the year ended December 31,
2008.
 
 In August
2008, the Trust sold the remaining portion of the USOGP business, comprised of
an approximate 96 percent interest in BreitBurn Energy Company L.P., for total
consideration of U.S. $300.4 million, consisting of cash proceeds, net of
transaction costs, of U.S. $290.4 million and a U.S. $10 million
note.  The Trust has recorded a gain on sale of $75.7 million and
$66.9 million in current tax expense related to this
transaction.  Also recorded was a realized foreign exchange loss of
$26.8 million, representing the recognition of the related portion of the
foreign exchange loss in accumulated other comprehensive income, which was
generated since acquisition in 2004.  These amounts are recorded as
part of net income from discontinued operations for the year ended December 31,
2008.
 
 Quicksilver
Resources Inc. ("Quicksilver") filed a lawsuit on October 31, 2008 against the
MLP, certain of its directors (including three Provident nominees), and
Provident.  The claim relates to a transaction between the MLP and
Quicksilver and certain other MLP matters. Quicksilver alleges, among other
things, that it was induced to enter into a contribution agreement pursuant to
which it contributed assets to the MLP by false representations as
to
   Provident
Energy 2008 Management’s Discussion and Analysis
 - 36
-
 
 Provident’s
relationship with the MLP. The transaction involved the issuance by the MLP to
Quicksilver of approximately U.S.$700 million of units of the MLP. The
litigation is in its very early stages, and it is not possible at this time to
assess the potential exposure of Provident in the event of an adverse verdict.
Provident believes the claims made against it in the lawsuit are without merit
and will vigorously defend itself and its named director nominees against these
claims.
 
 
 Foreign
ownership
 
 Based on
information received from our transfer agent and financial intermediaries in
January 2009, an estimated 85 percent of our outstanding trust units are held by
non-residents. However, this estimate may not be accurate as it is based on
certain assumptions and data from the securities industry that does not have a
well-defined methodology to determine the residency of beneficial holders of
securities.
 
 The Trust
qualifies as a Mutual Fund Trust under the Canadian Income Tax Act because
substantially all the value of its asset portfolio is derived from non-taxable
Canadian properties, comprised principally of royalties and interest on
inter-company debt.  Provident monitors on an ongoing basis the value
of its asset portfolio to confirm that substantially all of the value of its
asset portfolio is derived from non-taxable Canadian properties.
 
 On
September 17, 2003, Canadian unitholders approved an amendment to the Trust’s
Trust Indenture providing that residency restriction provisions need not be
enforced while the Trust continues to qualify as a Mutual Fund Trust under
Canadian tax legislation.  To allow Provident to remain a Mutual Fund
Trust and to execute a business plan that maximizes unitholder returns without
regard to the types of assets the Trust may hold, the approved amendment
provides for Provident’s Board of Directors to have sole discretion to determine
whether and when it is appropriate to reduce or limit the number of trust units
held by non-residents of Canada.
 
 
 Critical
accounting estimates
 
 Provident’s
significant accounting policies are described in note 2 to the consolidated
financial statements. Certain accounting policies include critical accounting
estimates.  These policies require management to make judgments and
estimates based on conditions and assumptions that are inherently
uncertain.  These accounting policies could result in materially
different results should the underlying assumptions or conditions
change.
 
 Management
assumptions are based on Provident’s historical experience, management’s
experience, and other factors that, in management’s opinion, are relevant and
appropriate.  Management assumptions may change over time, as further
experience is gained or as operating conditions change.
 
 The
Trust’s financial and operating results incorporate certain estimates
including:
  ·
              depletion,
      depreciation and accretion based on estimated oil and gas
      reserves;
 ·
              future
      recoverable value of property, plant and equipment and goodwill (see
      “Goodwill”) based on estimated future cash
  flows;
 ·
              value
      of asset retirement obligations based on estimated future costs and timing
      of expenditures;
 ·
              fair
      values of derivative contracts that are subject to fluctuation depending
      upon underlying commodity prices and foreign exchange rates (see note 13
      to the consolidated financial statements);
and
 ·
              income
      taxes based on estimates of future income and tax pool claims (see
      “Taxes”).
 
 Property,
plant and equipment
 
 Provident
follows the full cost method of accounting, whereby all costs associated with
the acquisition and development of oil and natural gas reserves are
capitalized.  Utilization of the full cost method of accounting
requires the use of management estimates and assumptions for amounts recorded
for depletion and depreciation of property, plant and equipment as well as for
the ceiling test.
   Provident
Energy 2008 Management’s Discussion and Analysis
 - 37
-
 
 The
provision for depletion and depreciation is calculated using the unit of
production method based on current production divided by Provident’s share of
estimated total proved oil and natural gas reserve volumes before
royalties.  The recoverability of a cost centre is tested by comparing
the carrying value of the cost centre to the sum of the undiscounted cash flows
expected from the cost centre.  If the carrying value is not
recoverable the cost centre is written down to its fair value.
 
 Proved
reserves are an estimate, under existing reserve evaluation polices, of volumes
that can reasonably be expected to be economically recoverable under existing
technology and economic conditions.  Changes in underlying assumptions
or economic conditions could have a material impact on Provident’s financial
results.  To mitigate these risks, management utilizes McDaniel &
Associates Consultants Ltd. and AJM Petroleum Consultants, independent
engineering firms, to evaluate Provident’s reserves.
 
 Estimates
of future production, oil and natural gas prices and future costs used in the
ceiling test are, by their very nature, subject to uncertainty and changes in
underlying assumptions could have a material impact on Provident’s financial
results.
 
 Asset
retirement obligation
 
 Under the
asset retirement obligation (ARO) standard, the fair value of asset retirement
obligations is recorded as a liability on a discounted basis, when
incurred.  The value of the related assets is increased by the same
amount as the liability and depreciated over the useful life of the
asset.  Over time the liability is adjusted for the change in present
value of the liability or as a result of changes to either the timing or amount
of the original estimate of undiscounted future cash flows.
 
 Asset
retirement obligation requires that management make estimates and assumptions
regarding future liabilities and cash flows involving environmental reclamation
and remediation.  Such assumptions are inherently uncertain and
subject to change over time due to factors such as historical experience,
changes in environmental legislation or improved
technologies.  Changes in underlying assumptions, based on the above
noted factors, could have a material impact on Provident’s financial
results.
 
 
 Change
in accounting policies
  (i)
                Inventory
 In
      the first quarter of 2008, the Trust adopted the new accounting standard,
      CICA Handbook Section 3031 - Inventories, which replaced the previous
      standard for inventories, Section 3030.  The main features of
      the new Section are as
follows:
 •
              measurement
      of inventories at the lower of cost and net realizable
    value;
 •
              consistent
      use of either first-in, first-out or a weighted average cost formula to
      measure cost;
 •
              reversal
      of previous write-downs to net realizable value when there is a subsequent
      increase to the value of
inventories.
  Adoption
      of the new Section has not had a material impact on the consolidated
      financial
statements.
 (ii)
              Capital
      disclosures
  In
      the first quarter of 2008, the Trust adopted CICA Handbook Section 1535
      “Capital Disclosures” which addresses the requirements for an entity to
      disclose qualitative information about its objectives, policies and
      processes for managing capital. This section also establishes the
      requirement for an entity to disclose quantitative data about what it
      regards as capital as well as disclose whether it has complied with any
      externally imposed capital requirements and, if not, the consequences of
      such non-compliance. The new disclosure is included in note
      14.
 Provident
Energy 2008 Management’s Discussion and Analysis
 - 38
-
 
 (iii)
                Financial
      instruments – disclosures
  In
      the first quarter of 2008, the Trust adopted CICA Handbook Section 3862
      “Financial Instruments-    Disclosures” and Section
      3863 “Financial Instruments-Presentation”. Section 3862 requires entities
      to provide disclosures in their financial statements that enable users to
      evaluate the significance of financial instruments to the entity’s
      financial position and performance. It also requires that entities
      disclose the nature and extent of risks arising from financial instruments
      and how the entity manages those risks. Section 3863 establishes
      presentation guidelines for financial instruments and non-financial
      derivatives and addresses the classification of financial instruments,
      from the perspective of the issuer, between liabilities and equity, the
      classification of related interest, dividends, losses and gains, and
      circumstances in which financial assets and financial liabilities are
      offset.  The new disclosure is included in note
      13.
 (iv)
              International
      Financial Reporting Standards
(IFRS)
  During
      2008, the Canadian Accounting Standards Board (AcSB) confirmed that
      publicly accountable enterprises will be required to adopt International
      Financial Reporting Standards (IFRS) in place of Canadian GAAP for interim
      and annual reporting purposes.  The required changeover date is
      for fiscal years beginning on or after January 1, 2011.
                          
                          Provident
      has commenced the process to transition from current Canadian GAAP to
      IFRS.  It has established a project plan and a project
      team.  The project team is led by finance management and
      includes representatives from various areas of the organization as
      necessary to plan for a smooth transition to IFRS.
                          
                          The
      project plan consists of three phases: initiation, detailed assessment and
      design and implementation.  Provident has completed the first
      phase, which involved the development of a detailed timeline for assessing
      resources and training and the completion of a high level review of the
      major differences between current Canadian GAAP and
      IFRS.  Education and training sessions for employees throughout
      the organization and discussions with Provident’s external auditors have
      commenced and will continue throughout the subsequent
      phases.  Regular reporting is provided to Provident’s senior
      management and to the Audit Committee of the Board of
      Directors.
                          
                          Provident
      is currently engaged in the detailed assessment and design phase of the
      project.  The detailed assessment and design phase involves
      established work teams to complete a comprehensive analysis of the impact
      of the IFRS differences identified in the initial scoping
      assessment.  In addition, an initial evaluation of IFRS 1
      transition exemptions and an analysis of financial systems has
      commenced.
                          
                          During
      the implementation phase, Provident will execute the required changes to
      business processes, financial systems, accounting policies, disclosure
      controls and internal controls over financial reporting.  At
      this time, the impact on the consolidated financial statements is not
      reasonably
determinable.
  For
recent accounting pronouncements, see note 3 to consolidated financial
statements.
   Business
risks
 
 The trust
industry is subject to risks that can affect the amount of funds flow from
operations available for distribution to unitholders, and the ability to
grow.  These risks include but are not limited to:
  ·
              capital
      markets, credit and liquidity risks and the ability to finance future
      growth; and
  ·
              the
      impact of Canadian governmental regulation on Provident, including the
      effect of the new tax on trust
distributions.
 
 The oil
and natural gas industry is subject to numerous risks that can affect the amount
of cash flow available for distribution to unitholders and the ability to
grow.  These risks include but are not limited to:
  
 Provident
Energy 2008 Management’s Discussion and Analysis
 - 39
-
  ·
                fluctuations
      in commodity price, exchange rates and interest
  rates;
 ·
              government
      and regulatory risk in respect of royalty and income tax
      regimes;
  ·
              changes
      to environmental regulations;
  ·
              operational
      risks that may affect the quality and recoverability of
      reserves;
  ·
              geological
      risk associated with accessing and recovering new quantities of
      reserves;
  ·
              transportation
      risk in respect of the ability to transport oil and natural gas to
      market;
  ·
              marketability
      of oil and natural gas;
  ·
              the
      ability to attract and retain employees;
and
  ·
              environmental,
      health and safety risks.
 
 The
midstream industry is also subject to risks that can affect the amount of cash
flow available for distribution to unitholders and the ability to grow. These
risks include but are not limited to:
  ·
              operational
      matters and hazards including the breakdown or failure of equipment,
      information systems or processes, the performance of equipment at levels
      below those originally intended, operator error, labour disputes, disputes
      with owners of interconnected facilities and carriers and catastrophic
      events such as natural disasters, fires, explosions, fractures, acts of
      eco-terrorists and saboteurs, and other similar events, many of which are
      beyond the control of the Trust or
Provident;
  ·
              the
      Midstream NGL assets are subject to competition from other gas processing
      plants, and the pipelines and storage, terminal and processing facilities
      are also subject to competition from other pipelines and storage, terminal
      and processing facilities in the areas they serve, and the gas products
      marketing business is subject to competition from other marketing
      firms;
  ·
              exposure
      to commodity price fluctuations;
  ·
              the
      ability to attract and retain
employees;
  ·
              regulatory
      intervention in determining processing fees and tariffs;
    and
  ·
              reliance
      on significant customers.
  Provident
strives to minimize these business risks by:
  ·
              employing
      and empowering management and technical staff with extensive industry
      experience and providing competitive
  remuneration;
  ·
              adhering
      to a strategy of acquiring, developing and optimizing quality, low-risk
      reserves in areas where we have technical and operational
      expertise;
  ·
              developing
      a diversified, balanced asset portfolio that generally offers developed
      operational infrastructure, year-round access and close proximity to
      markets;
  ·
              adhering
      to a disciplined Commodity Price Risk Management Program to mitigate the
      impact that volatile commodity prices have on cash flow available for
      distribution;
  ·
              marketing
      crude oil and natural gas to a diverse group of customers, including
      aggregators, industrial users, well-capitalized third-party marketers and
      spot market buyers;
  ·
              marketing
      natural gas liquids and related services to selected, credit worthy
      customers at competitive rates;
  ·
              maintaining
      a competitive cost structure to maximize cash flow and
      profitability;
  ·
              maintaining
      prudent financial leverage and developing strong relationships with the
      investment community and capital
providers;
  
 Provident
Energy 2008 Management’s Discussion and Analysis
 - 40
-
 
 ·
              adhering
      to strict guidelines and reporting requirements with respect to
      environmental, health and safety practices;
and
  ·
              maintaining
      an adequate level of property, casualty, comprehensive and directors’ and
      officers’ insurance coverage.
 
 Readers
should be aware that the risks set forth herein are not
exhaustive.  Readers are referred to Provident’s annual information
form, which is available at www.sedar.com, for a
detailed discussion of risks affecting Provident.
 
 Unit
trading activity
 
 The
following table summarizes the unit trading activity of the Provident units for
each of the four quarters in the year ended December 31, 2008 on both the
Toronto Stock Exchange and the New York Stock Exchange:
  Q1
                
                
                
                Q2
                
                
                
                Q3
                
                
                
                Q4TSE
      – PVE.UN (Cdn$)High
                
                $
                11.37
                
                
                $
                12.25
                
                
                $
                11.66
                
                
                $
                9.55Low
                
                $
                8.80
                
                
                $
                10.76
                
                
                $
                8.71
                
                
                $
                4.68Close
                
                $
                10.95
                
                
                $
                11.74
                
                
                $
                9.50
                
                
                $
                5.35Volume
      (000s)
                
                
                34,702
                
                
                
                28,161
                
                
                
                26,269
                
                
                
                31,780NYSE
      – PVX  (US$)High
                
                $
                11.28
                
                
                $
                12.40
                
                
                $
                11.50
                
                
                $
                9.00Low
                
                $
                8.50
                
                
                $
                10.50
                
                
                $
                8.50
                
                
                $
                3.64Close
                
                $
                10.60
                
                
                $
                11.43
                
                
                $
                8.98
                
                
                $
                4.36Volume
      (000s)
                
                
                74,533
                
                
                
                77,141
                
                
                
                76,617
                
                
                
                147,340
  Forward-looking
information
 
 This
MD&A contains forward-looking information under applicable securities
legislation.  Statements which include forward-looking information
relate to future events or the Trust's future performance.  Such
forward-looking information is provided for the purpose of providing information
about management's current expectations and plans relating to the
future.  Readers are cautioned that reliance on such information may
not be appropriate for other purposes, such as making investment
decisions.  All statements other than statements of historical fact
are forward-looking information.  In some cases, forward-looking
information can be identified by terminology such as "may", "will", "should",
"expect", "plan", "anticipate", "believe", "estimate", "predict", "potential",
"continue", or the negative of these terms or other comparable
terminology.  Statements relating to "reserves" or "resources" are
deemed to be forward-looking information, as they involve the implied
assessment, based on certain estimates and assumptions, that the resources and
reserves described can be profitably produced in the future.  Forward
looking information in this MD&A includes, but is not limited to, business
strategy and objectives, reserve quantities and the discounted present value of
future net cash flows from such reserves, net revenue, future production levels,
capital expenditures, exploration plans, development plans, acquisition and
disposition plans and the timing thereof, operating and other costs, royalty
rates, budgeted levels of cash distributions and the performance associated with
Provident's natural gas midstream, NGL processing and marketing
business.  Forward-looking information is based on current
expectations, estimates and projections that involve a number of risks and
uncertainties which could cause actual events or results to differ materially
from those anticipated by the Trust and described in the forward-looking
information.  In addition, this MD&A may contain forward-looking
information attributed to third party industry sources.  Undue
reliance should not be placed on forward-looking information, as there can be no
assurance that the plans, intentions or expectations upon which they are based
will occur.  By its nature, forward-looking information involves
numerous assumptions, known and unknown risks and uncertainties, both general
and specific, that contribute to the possibility that the predictions,
forecasts, projections and other forward-looking information will not
occur.  Forward-looking information in this MD&A includes, but is
not limited to, statements with respect to:
  ·
              the
      Trust's ability to benefit from the combination of growth opportunities
      and the ability to grow through the capital
  markets;
 
 Provident
Energy 2008 Management’s Discussion and Analysis
 - 41
-
 
 ·
              the
      Trust's acquisition strategy, the criteria to be considered in connection
      therewith and the benefits to be derived
  therefrom;
 ·
              sustainability
      and growth of production and reserves through prudent management and
      acquisitions;
 ·
              the
      emergence of accretive growth
opportunities;
 ·
              the
      ability to achieve an appropriate level of monthly cash
      distributions;
 ·
              the
      impact of Canadian governmental regulation on the
  Trust;
 ·
              the
      existence, operation and strategy of the commodity price risk management
      program;
 ·
              the
      approximate and maximum amount of forward sales and hedging to be
      employed;
 ·
              changes
      in oil and natural gas prices and the impact of such changes on cash flow
      after financial derivative
instruments;
 ·
              the
      level of capital expenditures devoted to development activity rather than
      exploration;
 ·
              the
      sale, farming out or development using third party resources to exploit or
      produce certain exploration
properties;
 ·
              the
      use of development activity and acquisitions to replace and add to
      reserves;
 ·
              the
      quantity of oil and natural gas reserves and oil and natural gas
      production levels;
 ·
              currency,
      exchange and interest rates;
 ·
              the
      performance characteristics of Provident's midstream, NGL processing and
      marketing business;
 ·
              the
      growth opportunities associated with the midstream, NGL processing and
      marketing business; and
 ·
              the
      nature of contractual arrangements with third parties in respect of
      Provident's midstream, NGL processing and marketing
    business.
 
 Although
the Trust believes that the expectations reflected in the forward-looking
information are reasonable, there can be no assurance that such expectations
will prove to be correct.  The Trust can not guarantee future results,
levels of activity, performance, or achievements.  Moreover, neither
the Trust nor any other person assumes responsibility for the accuracy and
completeness of the forward-looking information.  Some of the risks
and other factors, some of which are beyond the Trust's control, which could
cause results to differ materially from those expressed in the forward-looking
information contained in this MD&A include, but are not limited
to:
  ·
              general
      economic and credit conditions in Canada, the United States and
      globally;
 ·
              industry
      conditions associated with the NGL services, processing and marketing
      business;
 ·
              fluctuations
      in the price of crude oil, natural gas and natural gas
      liquids;
 ·
              uncertainties
      associated with estimating
reserves;
 ·
              royalties
      payable in respect of oil and gas
production;
 ·
              interest
      payable on notes issued in connection with
  acquisitions;
 ·
              income
      tax legislation relating to income trusts, including the effect of
      legislation taxing trust income;
 ·
              governmental
      regulation in North America of the oil and gas industry, including income
      tax and environmental regulation;
 ·
              fluctuation
      in foreign exchange or interest
rates;
 ·
              stock
      market volatility and market
valuations;
 ·
              the
      impact of environmental events;
 ·
              the
      need to obtain required approvals from regulatory
    authorities;
 ·
              unanticipated
      operating events which can reduce production or cause production to be
      shut-in or delayed;
 ·
              failure
      to realize the anticipated benefits of
  acquisitions;
 ·
              competition
      for, among other things, capital reserves, undeveloped lands and skilled
      personnel;
 ·
              failure
      to obtain industry partner and other third party consents and approvals,
      when required;
 ·
              risks
      associated with foreign ownership;
 ·
              third
      party performance of obligations under contractual arrangements;
      and
 ·
              the
      other factors set forth under "Business risks" in this
      MD&A.
 
 Readers
are cautioned that the foregoing list is not exhaustive of all possible risks
and uncertainties.  With respect to developing forward-looking
information contained in this MD&A, the Trust has made assumptions
regarding, among other things:
  
 Provident
Energy 2008 Management’s Discussion and Analysis
 - 42
-
 
 
  ·
              future
      natural gas and crude oil prices;
 ·
              the
      ability of the Trust to obtain qualified staff and equipment in a timely
      and cost-efficient manner to meet
demand;
 ·
              the
      regulatory framework regarding royalties, taxes and environmental matters
      in which the Trust conducts its
business;
 ·
              the
      impact of increasing competition;
 ·
              the
      Trust's ability to obtain financing on acceptable
  terms;
 ·
              the
      general stability of the economic and political environment in which the
      Trust operates;
 ·
              the
      timely receipt of any required regulatory
  approvals;
 ·
              the
      ability of the operator of the projects which the Trust has an interest in
      to operate the field in a safe, efficient and effective
      manner;
 ·
              field
      production rates and decline rates;
 ·
              the
      ability to replace and expand oil and natural gas reserves through
      acquisition, development of
exploration;
 ·
              the
      timing and costs of pipeline, storage and facility construction and
      expansion and the ability of the Trust to secure adequate product
      transportation;
 ·
              currency,
      exchange and interest rates; and
 ·
              the
      ability of the Trust to successfully market its oil and natural gas
      products.
 
 Readers
are cautioned that the foregoing list is not exhaustive of all factors and
assumptions which have been used.  Forward-looking information
contained in this MD&A is made as of the date hereof and the Trust
undertakes no obligation to update publicly or revise any forward-looking
information, whether as a result of new information, future events or otherwise,
unless required by applicable securities laws. The forward-looking information
contained in this MD&A is expressly qualified by this cautionary
statement.
 
 
 Additional
information
 
 Additional
information concerning Provident can be accessed under Provident’s public
filings at www.sedar.com and
www.sec.gov/edgar.shtml,
as well as on Provident’s website at www.providentenergy.com.
 
 
 Selected
annual financial measures
  ($
      000s except per unit data)
                
                2008
                
                
                2007
                
                
                2006Revenue
      from continuing operations (net of royalties and financial derivative
      instruments)
                
                $
                3,239,163
                
                
                $
                2,038,515
                
                
                $
                2,023,178Net
      income
                
                
                157,392
                
                
                
                30,434
                
                
                
                140,920Net
      income per unit - basic and diluted
                
                
                0.62
                
                
                
                0.13
                
                
                
                0.72Total
      assets
                
                
                3,074,069
                
                
                
                5,758,792
                
                
                
                3,370,919Long-term
      financial liabilities from continuing operations (1)
                
                
                867,232
                
                
                
                1,382,921
                
                
                
                1,065,932Declared
      distributions per unit.
                
                $
                1.38
                
                
                $
                1.44
                
                
                $
                1.44(1)
      Includes long-term debt, asset retirement obligation, long-term financial
      derivative instruments and other long-term liabilities.
 
 Provident
Energy 2008 Management’s Discussion and Analysis
 - 43
-
 
 Quarterly
table
 
 Segmented
      information by quarter($
      000s except for per unit and operating amounts)
                2008First
                      Quarter
                
                Second
                      Quarter
                Third
                      Quarter
                
                Fourth
                      Quarter
                Annual
                  TotalFinancial
      - consolidatedRevenue
      (continuing operations)
                $
                702,215
                $
                420,220
                $
                1,097,408
                $
                1,019,320
                $
                3,239,163Funds
      flow from operations
                $
                180,230
                $
                241,487
                $
                151,661
                $
                81,779
                $
                655,157Net
      income (loss)
                $
                33,616
                $
                (184,081)
                $
                351,105
                $
                (43,248)
                $
                157,392Net
      income (loss) per unit - basic
                $
                0.13
                $
                (0.72)
                $
                1.37
                $
                (0.17)
                $
                0.62Net
      income (loss) per unit - diluted
                $
                0.13
                $
                (0.72)
                $
                1.29
                $
                (0.17)
                $
                0.62Unitholder
      distributions
                $
                91,117
                $
                91,662
                $
                92,188
                $
                77,324
                $
                352,291Distributions
      per unit
                $
                0.36
                $
                0.36
                $
                0.36
                $
                0.30
                $
                1.38Oil
      and gas production (continuing operations)Cash
      revenue
                
                $
                122,815
                $
                164,442
                $
                158,400
                $
                101,437
                $
                547,094Earnings
      before interest, DD&A, taxes and other non-cash items
                $
                75,348
                $
                117,132
                $
                111,256
                $
                49,757
                $
                353,493Funds
      flow from operations
                $
                71,142
                $
                112,869
                $
                107,442
                $
                47,187
                $
                338,640Net
      income (loss)
                $
                9,591
                $
                28,935
                $
                76,881
                $
                (421,457)
                $
                (306,050)Provident
      MidstreamCash
      revenue
                
                $
                641,673
                $
                662,315
                $
                652,753
                $
                513,860
                $
                2,470,601Earnings
      before interest, DD&A, taxes and other non-cash items
                $
                75,987
                $
                61,769
                $
                37,339
                $
                37,666
                $
                212,761Funds
      flow from operations
                $
                59,252
                $
                52,601
                $
                32,537
                $
                34,592
                $
                178,982Net
      income (loss)
                $
                15,516
                $
                (290,230)
                $
                232,966
                $
                359,166
                $
                317,418OperatingOil
      and gas production (continuing operations)Light/medium
      oil (bpd)
                
                10,535
                
                10,179
                
                10,109
                
                9,885
                
                10,176Heavy
      oil (bpd)
                
                1,752
                
                2,315
                
                2,696
                
                2,422
                
                2,297Natural
      gas liquids (bpd)
                
                1,307
                
                1,178
                
                1,195
                
                1,134
                
                1,203Natural
      gas (mcfd)
                
                83,970
                
                86,130
                
                85,628
                
                80,450
                
                84,039Oil
      equivalent (boed)
                
                27,589
                
                28,027
                
                28,271
                
                26,849
                
                27,683Average
      selling price net of transportation expense
                  (continuing
      operations) (Cdn$)Crude
      oil per bbl
                $
                75.06
                $
                105.13
                $
                102.66
                $
                47.33
                $
                82.79(before
      realized financial derivative instruments)Crude
      oil per bbl
                $
                71.54
                $
                98.68
                $
                97.61
                $
                52.71
                $
                80.36(including
      realized financial derivative instruments)Natural
      gas liquids per barrel
                $
                72.85
                $
                94.59
                $
                91.72
                $
                47.64
                $
                76.88Natural
      gas per mcf
                $
                7.61
                $
                9.98
                $
                8.60
                $
                6.63
                $
                8.23(before
      realized financial derivative instruments)Natural
      gas per mcf
                $
                7.74
                $
                9.73
                $
                8.45
                $
                6.92
                $
                8.23(including
      realized financial derivative instruments)Provident
      MidstreamProvident
      Midstream NGL sales volumes (bpd)
                136,320
                
                110,826
                
                111,313
                
                120,222
                
                119,649
  Provident
Energy 2008 Management’s Discussion and Analysis
 - 44
-
 Quarterly
table
 
 Segmented
      information by quarter($
      000s except for per unit and operating amounts)
                2007First
                  Quarter
                
                Second
                  Quarter
                Third
                  Quarter
                
                Fourth
                  Quarter
                Annual
                  TotalFinancial
      - consolidatedRevenue
      (continuing operations)
                $
                558,807
                $
                463,995
                $
                494,065
                $
                521,648
                $
                2,038,515Funds
      flow from operations
                $
                87,040
                $
                98,503
                $
                105,149
                $
                177,563
                $
                468,255Net
      income (loss)
                $
                43,093
                $
                (46,199)
                $
                (35,005)
                $
                68,545
                $
                30,434Net
      income (loss) per unit - basic and diluted
                $
                0.20
                $
                (0.21)
                $
                (0.14)
                $
                0.28
                $
                0.13Unitholder
      distributions
                $
                76,271
                $
                80,236
                $
                87,782
                $
                89,063
                $
                333,352Distributions
      per unit
                $
                0.36
                $
                0.36
                $
                0.36
                $
                0.36
                $
                1.44Oil
      and gas production (continuing operations)Cash
      revenue
                
                $
                84,668
                $
                90,028
                $
                92,419
                $
                101,746
                $
                368,861Earnings
      before interest, DD&A, taxes and other non-cash items
                $
                49,756
                $
                55,457
                $
                53,530
                $
                63,009
                $
                221,752Funds
      flow from operations
                $
                46,410
                $
                52,032
                $
                47,143
                $
                58,667
                $
                204,252Net
      (loss) income
                $
                (4,510)
                $
                50,429
                $
                (17,807)
                $
                16,953
                $
                45,065Provident
      MidstreamCash
      revenue
                
                $
                453,272
                $
                397,713
                $
                433,950
                $
                598,963
                $
                1,883,898Earnings
      before interest, DD&A, taxes and other non-cash items
                $
                52,853
                $
                35,974
                $
                47,425
                $
                89,423
                $
                225,675Funds
      flow from operations
                $
                39,404
                $
                29,569
                $
                32,350
                $
                77,109
                $
                178,432Net
      income (loss)
                $
                51,838
                $
                (142,191)
                $
                (8,630)
                $
                (62,037)
                $
                (161,020)OperatingOil
      and gas production (continuing operations)Light/medium
      oil (bpd)
                
                6,428
                
                6,692
                
                8,858
                
                9,483
                
                7,876Heavy
      oil (bpd)
                
                1,669
                
                1,918
                
                2,324
                
                1,769
                
                1,921Natural
      gas liquids (bpd)
                
                1,422
                
                1,311
                
                1,255
                
                1,277
                
                1,316Natural
      gas (mcfd)
                
                88,928
                
                94,437
                
                93,511
                
                92,584
                
                92,378Oil
      equivalent (boed)
                
                24,340
                
                25,660
                
                28,022
                
                27,960
                
                26,509Average
      selling price net of transportation expense (continuing operations)
      (Cdn$)Crude
      oil per bbl
                $
                51.23
                $
                53.75
                $
                57.88
                $
                61.75
                $
                56.74(before
      realized financial derivative instruments)Crude
      oil per bbl
                $
                51.25
                $
                52.77
                $
                55.47
                $
                57.23
                $
                54.53(including
      realized financial derivative instruments)Natural
      gas liquids per barrel
                $
                49.02
                $
                52.79
                $
                55.47
                $
                63.63
                $
                55.07Natural
      gas per mcf
                $
                7.48
                $
                7.27
                $
                4.94
                $
                6.08
                $
                6.42(before
      realized financial derivative instruments)Natural
      gas per mcf
                $
                7.37
                $
                7.20
                $
                5.63
                $
                6.68
                $
                6.71(including
      realized financial derivative instruments)Provident
      MidstreamProvident
      Midstream NGL sales volumes (bpd)
                125,033
                
                109,713
                
                112,386
                
                135,981
                
                120,785
 
 Provident
Energy 2008 Management’s Discussion and Analysis
 - 45
-




MANAGEMENT’S
REPORT ON INTERNAL CONTROL OVER FINANCIAL REPORTING
 The
management of Provident is responsible for establishing and maintaining adequate
internal control over financial reporting for the Trust.  Under the
supervision of our Chief Executive Officer and our Chief Financial Officer we
have conducted an evaluation of the effectiveness of our internal control over
financial reporting based on the Internal Control-Integrated Framework issued by
the Committee of Sponsoring Organizations of the Treadway Commission
(COSO).  Based on our assessment, we have concluded that as of
December 31, 2008, our internal control over financial reporting was
effective.
 
 Because
of its inherent limitations, internal control over financial reporting may not
prevent or detect misstatements.  Also, projections of any evaluation
of effectiveness to future periods are subject to the risk that controls may
become inadequate because of changes in conditions, or that the degree of
compliance with the policies or procedures may deteriorate.
 
 The
effectiveness of the Trust’s internal control over financial reporting as of
December 31, 2008, has been audited by PricewaterhouseCoopers LLP, independent
auditors, as stated in their report which appears herein.
 
 
 “signed”                                                                           “signed”
 
 Thomas
W.
Buchanan                                                   Mark
N. Walker
 Chief
Executive
Officer                                                  Chief
Financial Officer
 
 
 
 Calgary,
Alberta
 March 11,
2009
   Provident
Energy 2008 Financial Statements and Notes
 - 1
-
 MANAGEMENT’S
RESPONSIBILITY FOR FINANCIAL STATEMENTS
 
 The
management of Provident is responsible for the information included in this
Annual Report. The financial statements have been prepared in accordance with
accounting principles generally accepted in Canada and in accordance with
accounting policies detailed in the notes to the financial
statements.  Where necessary, the statements include amounts based on
management’s informed judgments and estimates.  Financial information
in the Annual Report is consistent with that presented in the financial
statements.
 
 PricewaterhouseCoopers
LLP, Chartered Accountants, appointed by the unitholders, have audited the
financial statements and conducted a review of internal accounting policies and
procedures to the extent required by generally accepted auditing standards, and
performed such tests as they deemed necessary to enable them to express an
opinion on the financial statements.
 
 The Board
of Directors, through its Audit Committee, is responsible for ensuring that
management fulfills its responsibility for financial reporting and internal
control.  The Audit Committee is composed of three independent
directors.  The Audit Committee reviews the financial content of the
Annual Report and reports its findings to the Board of Directors for its
consideration in approving the financial statements.
 
 
 “signed”                                                                           “signed”
 
 Thomas
W.
Buchanan                                                  Mark
N. Walker
 Chief
Executive
Officer                                                
Chief Financial Officer
 
 
 
 Calgary,
Alberta
 March 11,
2009
 Provident
Energy 2008 Financial Statements and Notes
 - 2
-
 
  To the
Unitholders of Provident Energy Trust
 
 We have
completed integrated audits of Provident Energy Trust’s (the “Trust”) 2008 and
2007 consolidated financial statements and of its internal control over
financial reporting as at December 31, 2008.  Our opinions, based on
our audits, are presented below.
 
  Consolidated
Financial statements
  We have
audited the accompanying consolidated balance sheets of Provident Energy Trust
as at December 31, 2008 and December 31, 2007, and the related consolidated
statements of
operations and accumulated income, comprehensive and accumulated other
comprehensive income and cash flows for each of the years then
ended.  These consolidated financial statements are the responsibility
of the Trust’s management. Our responsibility is to express an opinion on these
consolidated financial statements based on our audits.
 
 We
conducted our audits of the Trust’s consolidated financial statements in
accordance with Canadian generally accepted auditing standards and the standards
of the Public Company Accounting Oversight Board (United States). Those
standards require that we plan and perform an audit to obtain reasonable
assurance about whether the financial statements are free of material
misstatement.  An audit of financial statements includes examining, on
a test basis, evidence supporting the amounts and disclosures in the financial
statements.  A financial statement audit also includes assessing the
accounting principles used and significant estimates made by management, and
evaluating the overall financial statement presentation. We believe that our
audits provide a reasonable basis for our opinion.
 
 In our
opinion, the consolidated financial statements referred to above present fairly,
in all material respects, the financial position of the Trust as at December 31,
2008 and December 31, 2007 and the results of its operations and its cash flows
for each of the years then ended in accordance with Canadian generally accepted
accounting principles.
 
 Internal
control over financial reporting
  We have
also audited Provident Energy Trust’s internal control over financial reporting
as at December 31, 2008, based on criteria established in Internal Control - Integrated
Framework issued by the Committee of Sponsoring Organizations of the
Treadway Commission (COSO).  The Trust’s management is responsible for
maintaining effective internal control over financial reporting and for its
assessment of the effectiveness of internal control over financial reporting
included in the accompanying Management’s Report on Internal Control Over
Financial Reporting.  Our responsibility is to express an opinion on
the Trust’s internal control over financial reporting based on our
audit.
  “PricewaterhouseCoopers” refers to PricewaterhouseCoopers LLP, an
Ontario limited liability partnership, or, as the context requires, the
PricewaterhouseCoopers global network or other member firms of the network, each
of which is a separate and independent legal entity.
  Provident
Energy 2008 Annual and Fourth Quarter Results
 - 3
-
 
 We
conducted our audit of internal control over financial reporting in accordance
with the standards of the Public Company Accounting Oversight Board (United
States).  Those standards require that we plan and perform the audit
to obtain reasonable assurance about whether effective internal control over
financial reporting was maintained in all material respects.  An audit
of internal control over financial reporting includes obtaining an understanding
of internal control over financial reporting, assessing the risk that a material
weakness exists, testing and evaluating the design and operating effectiveness
of internal control based on the assessed risk, and performing such other
procedures as we consider necessary in the circumstances.  We believe
that our audit provides a reasonable basis for our opinion.
 
 A
company’s internal control over financial reporting is a process designed to
provide reasonable assurance regarding the reliability of financial reporting
and the preparation of financial statements for external purposes in accordance
with generally accepted accounting principles.  A company’s internal
control over financial reporting includes those policies and procedures that
(i) pertain to the maintenance of records that, in reasonable detail,
accurately and fairly reflect the transactions and dispositions of the assets of
the company; (ii) provide reasonable assurance that transactions are
recorded as necessary to permit preparation of financial statements in
accordance with generally accepted accounting principles, and that receipts and
expenditures of the company are being made only in accordance with
authorizations of management and directors of the company; and
(iii) provide reasonable assurance regarding prevention or timely detection
of unauthorized acquisition, use, or disposition of the company’s assets that
could have a material effect on the financial statements.
 
 Because
of its inherent limitations, internal control over financial reporting may not
prevent or detect misstatements.  Also, projections of any evaluation
of effectiveness to future periods are subject to the risk that controls may
become inadequate because of changes in conditions, or that the degree of
compliance with the policies or procedures may deteriorate.
 
 In our
opinion, the Trust maintained, in all material respects, effective internal
control over financial reporting as at December 31, 2008based on criteria
established in Internal Control — Integrated Framework issued by the
COSO.
 
 
 
 
 
 Chartered
Accountants
 March 11,
2009
 Provident
Energy 2008 Financial Statements and Notes
 - 4
-
 PROVIDENT
      ENERGY TRUSTCONSOLIDATED
      BALANCE SHEETSCanadian
      dollars (000s)As
      at
              
              
              As
      atDecember
      31,
              
              
              December
      31,2008
              
              
              2007AssetsCurrent
      assetsCash
      and cash equivalents
              
              $
              4,629
              
              
              $
              -Accounts
      receivable
              
              
              244,485
              
              
              
              338,105Petroleum
      product inventory
              
              
              46,160
              
              
              
              84,638Prepaid
      expenses and other current assets
              
              
              7,886
              
              
              
              8,313Financial
      derivative instruments (note 13)
              
              
              16,708
              
              
              
              1,329Assets
      held for sale - USOGP (note 15)
              
              
              -
              
              
              
              93,578319,868
              
              
              
              525,963Investments
      and other long term assets
              
              
              14,218
              
              
              
              5,862Long-term
      financial derivative instruments (note 13)
              
              
              735
              
              
              
              -Property,
      plant and equipment (note 5)
              
              
              2,480,503
              
              
              
              2,510,271Intangible
      assets (note 6)
              
              
              158,336
              
              
              
              171,793Goodwill
      (note 7)
              
              
              100,409
              
              
              
              517,299Assets
      held for sale - USOGP (note 15)
              
              
              -
              
              
              
              2,027,604$
              3,074,069
              
              
              $
              5,758,792LiabilitiesCurrent
      liabilitiesAccounts
      payable and accrued liabilities
              
              $
              244,031
              
              
              $
              347,224Cash
      distributions payable
              
              
              20,088
              
              
              
              25,100Current
      portion of convertible debentures (note 8)
              
              
              24,871
              
              
              
              19,198Financial
      derivative instruments (note 13)
              
              
              13,693
              
              
              
              130,276Liabilities
      held for sale - USOGP (note 15)
              
              
              -
              
              
              
              114,681302,683
              
              
              
              636,479Long-term
      debt - revolving term credit facility (note 8)
              
              
              504,685
              
              
              
              923,996Long-term
      debt - convertible debentures (note 8)
              
              
              236,123
              
              
              
              256,440Asset
      retirement obligation (note 9)
              
              
              59,432
              
              
              
              43,886Long-term
      financial derivative instruments (note 13)
              
              
              58,420
              
              
              
              146,199Other
      long-term liabilities (note 11)
              
              
              8,572
              
              
              
              12,400Future
      income taxes (note 12)
              
              
              267,807
              
              
              
              302,089Liabilities
      held for sale - USOGP (note 15)
              
              
              -
              
              
              
              628,502Non-controlling
      interests (note 15)Discontinued
      operations (USOGP)
              
              
              -
              
              
              
              1,100,136Unitholders’
      equityUnitholders’
      contributions (note 10)
              
              
              2,806,071
              
              
              
              2,750,374Convertible
      debentures equity component
              
              
              17,198
              
              
              
              18,213Contributed
      surplus (note 11)
              
              
              1,695
              
              
              
              801Accumulated
      other comprehensive loss
              
              
              (2,183
              )
              
              
              (69,188
              )Accumulated
      income
              
              
              426,034
              
              
              
              268,642Accumulated
      cash distributions
              
              
              (1,612,468
              )
              
              
              (1,260,177
              )1,636,347
              
              
              
              1,708,665$
              3,074,069
              
              
              $
              5,758,792The
      accompanying notes to the consolidated financial statements are an
      integral part of these statements.
  Onbehalf of the Board
of Directors:
  “signed”
                “signed”M.H.
      (Mike) Shaikh, FCA
                Thomas
      W. Buchanan, CADirector
                Director
 
 Provident
Energy 2008 Financial Statements and Notes
 - 5
-
 PROVIDENT
      ENERGY TRUSTCONSOLIDATED
      STATEMENT OF OPERATIONS AND ACCUMULATED INCOMECanadian
      dollars (000s except per unit amounts)Year
      endedDecember
      31,2008
              
              
              2007RevenueRevenue
              
              $
              3,147,714
              
              
              $
              2,325,505Realized
      loss on financial derivative instruments
              
              
              (130,019
              )
              
              
              (72,746
              )Unrealized
      gain (loss) on financial derivative instruments
              
              
              221,468
              
              
              
              (214,244
              )3,239,163
              
              
              
              2,038,515ExpensesCost
      of goods sold
              
              
              2,206,427
              
              
              
              1,594,639Production,
      operating and maintenance
              
              
              153,111
              
              
              
              126,481Transportation
              
              
              37,120
              
              
              
              25,018Depletion,
      depreciation and accretion
              
              
              343,315
              
              
              
              301,111Goodwill
      impairment (note 7)
              
              
              416,890
              
              
              
              -General
      and administrative (note 11)
              
              
              66,913
              
              
              
              62,353Interest
      on bank debt
              
              
              36,088
              
              
              
              44,221Interest
      and accretion on convertible debentures
              
              
              19,944
              
              
              
              14,687Foreign
      exchange (gain) loss and other
              
              
              (20,828
              )
              
              
              4,2023,258,980
              
              
              
              2,172,712Loss
      from continuing operations before taxes
              
              
              (19,817
              )
              
              
              (134,197
              )Capital
      tax expense
              
              
              3,109
              
              
              
              3,762Current
      and withholding tax (recovery) expense
              
              
              (4,529
              )
              
              
              6,352Future
      income tax recovery (note 12)
              
              
              (29,765
              )
              
              
              (28,356
              )(31,185
              )
              
              
              (18,242
              )Net
      income (loss) from continuing operations
              
              
              11,368
              
              
              
              (115,955
              )Net
      income from discontinued operations (note 15)
              
              
              146,024
              
              
              
              146,389Net
      income
              
              
              157,392
              
              
              
              30,434Accumulated
      income, beginning of year
              
              $
              268,642
              
              
              $
              238,208Accumulated
      income, end of year
              
              $
              426,034
              
              
              $
              268,642Net
      income (loss) from continuing operations per unit
                –
      basic and diluted
              
              $
              0.04
              
              
              $
              (0.50
              )Net
      income per unit
                –
      basic and diluted
              
              $
              0.62
              
              
              $
              0.13
  The
accompanying notes to the consolidated financial statements are an integral part
of these statements.
 Provident
Energy 2008 Financial Statements and Notes
 - 6
-
 PROVIDENT
      ENERGY TRUSTCONSOLIDATED
      STATEMENT OF CASH FLOWSCanadian
      dollars (000s)Year
      endedDecember
      31,2008
              
              
              2007Cash
      provided by operating activitiesNet
      income (loss) for the year from continuing operations
              
              $
              11,368
              
              
              $
              (115,955
              )Add
      (deduct) non-cash items:Depletion,
      depreciation and accretion
              
              
              343,315
              
              
              
              301,111Goodwill
      impairment (note 7)
              
              
              416,890
              
              
              
              -Non-cash
      interest expense and other
              
              
              5,291
              
              
              
              2,797Non-cash unit
      based compensation (recovery) expense (note 11)
              
              
              (4,117
              )
              
              
              8,064Unrealized
      (gain) loss on financial derivative instruments
              
              
              (221,468
              )
              
              
              214,244Unrealized
      foreign exchange (gain) loss and other
              
              
              (3,892
              )
              
              
              779Future
      income tax recovery (note 12)
              
              
              (29,765
              )
              
              
              (28,356
              )Funds
      flow from continuing operations
              
              
              517,622
              
              
              
              382,684Funds
      flow from discontinued operations
              
              
              137,535
              
              
              
              85,571Funds
      flow from operations
              
              
              655,157
              
              
              
              468,255Site
      restoration expenditures
              
              
              (6,381
              )
              
              
              (4,062
              )Change
      in non-cash operating working capital from continuing
      operations
              
              
              52,684
              
              
              
              4,807Change
      in non-cash operating working capital from discontinued
      operations
              
              
              (27,034
              )
              
              
              (4,545
              )674,426
              
              
              
              464,455Cash
      (used for) provided by financing activities(Decrease)
      increase in long-term debt
              
              
              (440,244
              )
              
              
              169,122Declared
      distributions to unitholders
              
              
              (352,291
              )
              
              
              (333,352
              )Issue
      of trust units, net of issue costs
              
              
              55,510
              
              
              
              412,909Change
      in non-cash financing working capital
              
              
              (5,028
              )
              
              
              2,856Financing
      activities from discontinued operations
              
              
              (47,511
              )
              
              
              1,011,670(789,564
              )
              
              
              1,263,205Cash
      provided by (used for) investing activitiesCapital
      expenditures
              
              
              (246,947
              )
              
              
              (178,113
              )Capitol
      Energy acquisition (note 4)
              
              
              -
              
              
              
              (467,495
              )Triwest
      Energy acquisition (note 4)
              
              
              -
              
              
              
              (2,300
              )Oil and
      gas property acquisitions
              
              
              (24,181
              )
              
              
              (13,050
              )Increase in
      investments
              
              
              (792
              )
              
              
              (5,450
              )Proceeds on
      sale of assets
              
              
              -
              
              
              
              7,624Proceeds on
      sale of discontinued operations, net of tax (note 15)
              
              
              457,906
              
              
              
              -Change
      in non-cash investing working capital
              
              
              (3,229
              )
              
              
              14,920Investing
      activities from discontinued operations
              
              
              (69,810
              )
              
              
              (1,087,278
              )112,947
              
              
              
              (1,731,142
              )(Decrease)
      increase in cash and cash equivalents
              
              
              (2,191
              )
              
              
              (3,482
              )Cash
      and cash equivalents, beginning of year
              
              
              6,820
              
              
              
              10,302Cash
      and cash equivalents, end of year
              
              $
              4,629
              
              
              $
              6,820Cash
      and cash equivalents, end of year from discontinued
    operations
              
              $
              -
              
              
              $
              6,820Cash
      and cash equivalents, end of year from continuing
    operations
              
              $
              4,629
              
              
              $
              -Supplemental
      disclosure of cash flow informationCash
      interest paid including debenture interest
              
              $
              63,490
              
              
              $
              69,600Cash
      taxes paid (note 15)
              
              $
              210,132
              
              
              $
              13,741The
      accompanying notes to the consolidated financial statements are an
      integral part of these statements.
  Provident
Energy 2008 Financial Statements and Notes
 - 7
-
 PROVIDENT
      ENERGY TRUSTCONSOLIDATED
      STATEMENT OF COMPREHENSIVE INCOMEAND
      ACCUMULATED OTHER COMPREHENSIVE INCOMECanadian
      Dollars (000s)Year
      endedDecember
      31,2008
              
              
              2007Net
      income
              
              $
              157,392
              
              
              $
              30,434Other
      comprehensive income (loss), net of taxesForeign
      currency translation adjustments
              
              
              10,315
              
              
              
              (25,083
              )Reclassification
      adjustment for foreign currency losses
                included
      in net income
              
              
              57,062
              
              
              
              -Unrealized loss
      on available-for-sale investments
                (net
      of taxes)
              
              
              (372
              )
              
              
              (1,811
              )67,005
              
              
              
              (26,894
              )Comprehensive
      income
              
              $
              224,397
              
              
              $
              3,540Accumulated
      other comprehensive loss, beginning of year
              
              
              (69,188
              )
              
              
              (42,294
              )Other
      comprehensive income (loss)
              
              
              67,005
              
              
              
              (26,894
              )Accumulated
      other comprehensive loss, end of year
              
              $
              (2,183
              )
              
              $
              (69,188
              )Accumulated
      income, end of year
              
              
              426,034
              
              
              
              268,642Accumulated
      cash distributions, end of year
              
              
              (1,612,468
              )
              
              
              (1,260,177
              )Retained
      earnings (deficit), end of year
              
              
              (1,186,434
              )
              
              
              (991,535
              )Accumulated
      other comprehensive loss, end of year
              
              
              (2,183
              )
              
              
              (69,188
              )Total
      retained earnings (deficit) and accumulated other
                comprehensive
      loss, end of year
              
              $
              (1,188,617
              )
              
              $
              (1,060,723
              )
 The
accompanying notes to the consolidated financial statements are an integral part
of these statements.
  
 Provident
Energy 2008 Financial Statements and Notes
 - 8
-
 
 Notes to
the Consolidated
 Financial
Statements
  (Tabular
amounts in Cdn $ 000’s, except unit and per unit amounts)
   December
31, 2008
  1.
                Structure
      of the Trust
 
 Provident
Energy Trust (the “Trust” or “Provident”) is an open-end unincorporated
investment trust created under the laws of Alberta pursuant to a trust indenture
dated January 25, 2001, amended from time to time.  The beneficiaries
of the Trust are the unitholders.  The Trust was established to hold,
directly and indirectly, all types of petroleum and natural gas and energy
related assets, including without limitation facilities of any kind, oil sands
interests, electricity or power generating assets and pipeline, gathering,
processing and transportation assets.  The Trust commenced operations
March 6, 2001.
 
 Cash flow
is provided to the Trust from properties owned and operated by Provident Energy
Ltd. and other directly and indirectly owned subsidiaries of the Trust. Cash
flow is paid to the Trust by way of royalty payments, interest payments and
principal debt repayments.  The cash payments received by the Trust
are subsequently distributed to the unitholders monthly.
  2.
                Significant
      accounting policies
 
 i)
                Principles of consolidation and
      investments
  The
consolidated financial statements include the accounts of the Trust, including
the consolidated accounts of all wholly and
 partially
owned subsidiaries, and are presented in accordance with Canadian generally
accepted accounting principles.
 Investments
subject to significant influence are accounted for using the equity
method.  Certain comparative figures have been
 reclassified
to conform to the current year presentation.  In particular, the
comparative figures have been reclassified to reflect
 discontinued
operations presentation for the United States oil and natural gas production
(USOGP) business (see note 15).
 
 ii)
                Financial
      instruments
  All
financial instruments, including derivatives, are recognized on the Trust’s
Consolidated Balance Sheet.  Derivatives are measured
 at fair
value with unrealized gains and losses reported in net
income.  Investments, other than investments accounted for by the
equity
 method,
are measured at fair value, with reference to published price quotations, and
unrealized gains and losses are reported in AOCI.
 The
Trust’s other financial instruments (accounts receivable, accounts payable and
accrued liabilities, cash distributions payable,
 and
long-term debt) are measured at amortized cost using the effective interest rate
method.  Transaction costs are included with the
 associated
financial instruments and amortized accordingly (see note 3).
 iii)
                  Cash and cash
      equivalents
 Cash
and cash equivalents include short-term investments, such as money market
deposits or similar type instruments, with an
 original
maturity of three months or less when purchased.
 iv)
                  Property, plant & equipment
      and intangible assets
 The
Trust follows the full cost method of accounting for oil and natural gas
exploration and development activities, whereby all
 costs
associated with the acquisition and development
of oil and natural gas reserves are   capitalized.  Such
costs include
 lease
acquisition, lease rentals on non-producing properties, geological
and geophysical
activities, drilling of productive
 and
non-productive wells, and tangible well equipment.  Gains or 
losses on the disposition of oil and gas properties are
 not
recognized unless the resulting change to
 
 Provident
Energy 2008 Financial Statements and Notes
 - 9
-
 
 the
depletion and depreciation rate is 20 percent or more.   All
other property, plant and equipment, including midstream assets, are recorded at
cost.  Expenditures relating to renewals or betterments that improve
the productive capacity or extend the life of property, plant and equipment are
capitalized.  Maintenance and repairs are expensed as
incurred.  Products required for line-fill and cavern bottoms are
presented as part of property, plant and equipment and are stated at the lower
of historic cost and net realizable value and are not depreciated.
 
 a)
                Depletion, depreciation and
      accretion
                  
                  The
      provision for depletion and depreciation for oil and natural gas assets is
      calculated, by cost centre, using the unit-of-production method based on
      current production divided by the Trust’s share of estimated total proved
      oil and natural gas reserve volumes, before
      royalties.  Production and reserves of natural gas and
      associated liquids are converted at the energy equivalent ratio of 6,000
      cubic feet of natural gas to one barrel of oil.  In determining
      its depletion base, the Trust includes estimated future costs for
      developing proved reserves, and excludes estimated salvage values of
      tangible equipment and the cost of unproved properties.
                    
                    Midstream
      facilities, including natural gas liquids storage facilities and natural
      gas liquids processing and extraction facilities are carried at cost and
      depreciated on a straight-line basis over the estimated service lives of
      the assets, which range from 30 to 40 years.  Intangible assets
      are amortized over the estimated useful lives of the assets, which range
      from 12 to 15 years.  Capital assets related to pipelines and
      office equipment are carried at cost and depreciated using the
      straight-line method over their economic
  lives.
   b)
                Impairment
                  
                  Oil
      and natural gas assets accounted for using the full cost method are
      subject to a ceiling test.  The ceiling test calculation is
      performed by comparing the carrying value of the cost centre to the sum of
      the undiscounted proved reserve cash flows expected from the cost centre
      by country using future price estimates.  If the carrying value
      is not recoverable, the cost centre is written down to its fair
      value.  Fair value is determined by the future cash flows from
      the proved plus probable reserves discounted at the Trust’s risk free
      interest rate.   Any excess carrying value of the assets on
      the balance sheet above fair value would be recorded in depletion,
      depreciation and accretion expense as a permanent impairment.
                    
                    For
      Midstream property, plant and equipment, and intangible assets, an
      impairment loss is recognized when the carrying amount exceeds the fair
      value.
   v)
                  Joint
      venture
                    
                    Provident
      conducts many of its activities through joint ventures and the accounts
      reflect only Provident’s proportionate interest in such
      activities.
 
 vi)
                Inventory
                  
                  Inventories of products are valued at the
      lower of average cost and net realizable value based on market
      prices.
  
 vii)
                Goodwill
  Goodwill,
which represents the excess of cost of an acquired enterprise over the net of
the amounts assigned to assets acquired and liabilities assumed, is assessed at
least annually for impairment.  To assess impairment, the fair value
of the reporting unit is determined and compared to the book value of the
reporting unit.  If the fair value is less than the book value, then a
second test is performed to determine the amount of the
impairment.  The amount of the impairment is determined by deducting
the fair value of the reporting unit’s assets and liabilities from the fair
value of the reporting unit to determine the implied fair value of goodwill and
comparing that amount to the book value of the reporting unit’s
goodwill.  Any excess of the book value of goodwill over the implied
fair value of goodwill is the impaired amount.  Goodwill is not
amortized.
 
 Provident
Energy 2008 Financial Statements and Notes
 - 10
-
 
 viii)
                Asset retirement
      obligation
  Under the
asset retirement obligation (“ARO”) standard the fair value of a liability for
an ARO is recorded in the period where a reasonable estimate of the fair value
can be determined.  When the liability is recorded, the carrying
amount of the related asset is increased by the same amount of the
liability.  The asset recorded is depleted over the useful life of the
asset.  Additions to asset retirement obligations due to the passage
of time are recorded as accretion expense. Actual expenditures incurred are
charged against the obligation.
 
 ix)
                Unit based
      compensation
  The Trust
uses the fair value method of valuing compensation expense associated with the
Trust’s unit option plan. Provident has applied this method to options issued
after January 1, 2003, the effective date for implementing stock based
compensation. Under the fair value method the amount to be recognized as expense
is determined at the time the options are issued and is recognized in earnings
over the vesting period of the options with a corresponding increase in
contributed surplus.
  The Trust
has established other unit based compensation plans whereby notional units are
granted to employees. The fair value of these notional units is estimated and
recorded as non-cash unit based compensation (a component of general and
administrative expenses).  A portion relating to operational employees
at field and plant locations is allocated to operating expense.  The
offsetting amount is recorded as accrued liabilities or other long-term
liabilities. A realization of the expense and a resulting reduction in cash
provided by operating activities occurs when a cash payment is
made.
 x)
                  Trust unit
      calculations
 The Trust
applies the treasury stock method to determine the dilutive effect of trust unit
rights and trust unit options.  Under the treasury stock method,
outstanding and exercisable instruments that will have a dilutive effect are
included in per unit - diluted calculations, ordered from most dilutive to least
dilutive.
 
 The
dilutive effect of convertible debentures is determined using the "if-converted"
method whereby the outstanding debentures at the end of the period are assumed
to have been converted at the beginning of the period or at the time of issue if
issued during the year.  Amounts charged to income or loss relating to
the outstanding debentures are added back to net income for the diluted
calculation. The units issued upon conversion are included in the denominator of
per unit - basic calculations from the date of issue.
 
 xi)
                Income
    taxes
  Provident
follows the liability method for calculating income
taxes.  Differences between the amounts reported in the financial
statements of the corporate subsidiaries and their respective tax bases are
applied to tax rates in effect to calculate the future tax
liability.  The effect of any change in income tax rates is recognized
in the current period income.
 
 The Trust
is a taxable entity under the Income Tax Act (Canada) and is currently 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 and meets the requirements of the Income Tax Act (Canada)
applicable to the Trust, no provision for current income taxes has been made in
the Trust.
  In 2007,
the Canadian government enacted Bill C-52, Budget Implementation Act
2007.  This bill contains legislation to tax publicly traded trusts,
commencing in 2011.  As a result of this legislation, the Trust
records the future income tax effect of the temporary differences on its flow
through entities that are expected to reverse subsequent to 2010.
 
 Provident
Energy 2008 Financial Statements and Notes
 - 11
-
 
 xii)
                Revenue
      recognition
  Revenue
associated with the sales of Provident’s natural gas, natural gas liquids
(“NGLs”) and crude oil owned by Provident is recognized when title passes from
Provident to its customer.
 
 Revenues
associated with the services provided where Provident acts as agent are recorded
on a net basis when the services are provided.  Revenues associated
with the sale of natural gas liquids storage services are recognized when the
services are provided.
 
 xiii)
                Foreign currency
      translation
  The
accounts of self-sustaining foreign operations are translated using the current
rate method, whereby assets and liabilities are translated at period-end
exchange rates, while revenue and expenses are translated using average rates
for the period.  Translation gains and losses related to
self-sustaining operations are deferred and included as a component of
accumulated other comprehensive income.  A proportionate amount of the
gain or loss is recognized in net income when there has been a reduction in the
net investment.
 
 The
accounts of integrated foreign operations are translated using the temporal
method, under which monetary assets and liabilities are translated at the
period-end exchange rate, other assets and liabilities at the historical rates,
and revenues and expenses at the rates for the period, except depreciation,
depletion and accretion which is translated on the same basis as the related
assets.  Translation gains and losses are included in income in the
period in which they arise.
 
 xiv)
                Use of
      estimates
  The
preparation of financial statements requires management to make estimates based
on currently available information.  Actual results could differ from
those estimated.  In particular, management makes estimates for
amounts recorded for depletion and depreciation of the property, plant and
equipment, financial derivative instruments, asset retirement obligation, unit
based compensation and income taxes.  The ceiling test uses factors
such as estimated reserves, production rates, estimated future petroleum and
natural gas prices and future costs.  Due to the inherent limitations
in metering and the physical properties of storage caverns and pipelines, the
determination of precise volumes of natural gas liquids held in inventory at
such locations is subject to estimation. Actual inventories of natural gas
liquids can only be determined by draining of the caverns.  By their
very nature, these estimates are subject to measurement uncertainty and the
effect on the financial statements of future periods could be
material.
 
 The
estimation of oil and gas reserves is a subjective process.  Forecasts
are based on engineering data, projected future rates of production, estimated
commodity prices, and the timing of future expenditures.  The Trust
expects reserve estimates to be revised based on the results of future drilling
activity, testing, production levels, and economics of recovery based on cash
flow forecasts.
 
  3.
                Changes
      in accounting policies and
practices
 
 A.Changes in
accounting policies
  (i)
                Inventory
 
 In the
first quarter of 2008, the Trust adopted the new accounting standard, CICA
Handbook Section 3031 - Inventories, which replaced the previous standard for
inventories, Section 3030.  The main features of the new Section are
as follows:
  •
                measurement
      of inventories at the lower of cost and net realizable
    value;
 •
                consistent
      use of either first-in, first-out or a weighted average cost formula to
      measure cost;
 •
                reversal
      of previous write-downs to net realizable value is required when there is
      a subsequent increase to the value of
  inventories.
 
 Adoption
of the new Section has not had a material impact on the consolidated financial
statements.
 
 Provident
Energy 2008 Financial Statements and Notes
 - 12
-
  (ii)
                Capital
      disclosures
  In the
first quarter of 2008, the Trust adopted CICA Handbook Section 1535 “Capital
Disclosures” which addresses the requirements for an entity to disclose
qualitative information about its objectives, policies and processes for
managing capital. This section also establishes the requirement for an entity to
disclose quantitative data about what it regards as capital as well as disclose
whether it has complied with any externally imposed capital requirements and, if
not, the consequences of such non-compliance. The new disclosure is included in
note 14.
  (iii)
                Financial instruments –
      disclosures
 
 In the
first quarter of 2008, the Trust adopted CICA Handbook Section 3862 “Financial
Instruments-Disclosures” and Section 3863 “Financial Instruments-Presentation”.
Section 3862 requires entities to provide disclosures in their financial
statements that enable users to evaluate the significance of financial
instruments to the entity’s financial position and performance. It also requires
that entities disclose the nature and extent of risks arising from financial
instruments and how the entity manages those risks. Section 3863 establishes
presentation guidelines for financial instruments and non-financial derivatives
and addresses the classification of financial instruments, from the perspective
of the issuer, between liabilities and equity, the classification of related
interest, dividends, losses and gains, and circumstances in which financial
assets and financial liabilities are offset.  The new disclosure is
included in note 13.
 
 B.Recent accounting pronouncements
 
 i)
                Goodwill and intangible
      assets
 
 In
February 2008, the CICA released section 3064 “Goodwill and Intangible assets”
which supersedes section 3062 “Goodwill and other Intangible assets” and section
3450 “Research and Development”.  This new section establishes
standards for the recognition, measurement and disclosure of goodwill and
intangible assets.  This section applies to annual and interim
financial statements relating to fiscal years beginning on or after October 1,
2008.  The Trust does not expect the adoption of this standard to have
a material impact on its consolidated financial statements.
 
 ii)
                International Financial
      Reporting Standards
 
 During
2008, the Canadian Accounting Standards Board (AcSB) confirmed that publicly
accountable enterprises will be required to adopt International Financial
Reporting Standards (IFRS) in place of Canadian GAAP for interim and annual
reporting purposes.  The required changeover date is for fiscal years
beginning on or after January 1, 2011.  At this time, the impact on
the Trust’s consolidated financial statements is not reasonably
determinable.
 
  4.
                Acquisitions
 
 i)
                Acquisition of Triwest
  On
December 3, 2007, the Trust acquired the common shares of Triwest Energy Inc.
(“Triwest”), for consideration of 6,251,149 trust units with an ascribed value
of $76.6 million plus acquisition costs of $0.8 million and cash consideration
of $1.5 million.  Triwest was a privately held company with oil assets
primarily in southeast Saskatchewan.  The transaction was accounted
for using the purchase method with the allocation of the purchase price as
follows:
 
 Provident
Energy 2008 Financial Statements and Notes
 - 13
-
  Net
      assets acquired and liabilities assumedProperty,
      plant and equipment
                  
                  $
                  115,719Working
      capital, net
                  
                  
                  (2,757
                  )Bank
      debt
                  
                  
                  (11,122
                  )Asset
      retirement obligation
                  
                  
                  (752
                  )Future
      income taxes
                  
                  
                  (22,211
                  )$
                  78,877ConsiderationAcquisition
      costs
                  
                  $
                  800Cash
                  
                  
                  1,5002,300Trust
      units issued
                  
                  
                  76,577$
                  78,877
  ii)
                Acquisition of
      Capitol
  On June
19, 2007, the Trust acquired Capitol Energy Resources Ltd. (“Capitol”) for cash
consideration of $467.5 million.  Capitol was a public oil and gas
exploration and production company active in the Western Canadian sedimentary
basin.  The transaction has been accounted for using the purchase
method with the allocation of the purchase price as follows:
 
 Net
      assets acquired and liabilities assumedProperty,
      plant and equipment
                  
                  $
                  522,707Goodwill
                  
                  
                  85,946Working
      capital, net
                  
                  
                  17,108Bank
      debt
                  
                  
                  (53,100
                  )Financial
      derivative instruments
                  
                  
                  (621
                  )Asset
      retirement obligation
                  
                  
                  (1,752
                  )Future
      income taxes
                  
                  
                  (102,793
                  )$
                  467,495ConsiderationAcquisition
      costs
                  
                  $
                  1,115Cash
                  
                  
                  466,380$
                  467,495
 The
Capitol acquisition was financed by the issuance of 29,313,727 trust units at
$12.75 per unit and Provident’s credit facility.
 
  5.           Property,
plant and equipment
  Year
      ended December 31, 2008
                  
                  Cost
                  
                  
                  Accumulated
                    depletion
      and
                    depreciation
                  
                  Net
      Book
                    valueOil
      and natural gas properties
                  
                  $
                  3,125,360
                  
                  
                  $
                  1,411,997
                  
                  $
                  1,713,363Midstream
      assets
                  
                  
                  827,172
                  
                  
                  
                  87,674
                  
                  
                  739,498Office
      equipment
                  
                  
                  44,678
                  
                  
                  
                  17,036
                  
                  
                  27,642Total
                  
                  $
                  3,997,210
                  
                  
                  $
                  1,516,707
                  
                  $
                  2,480,503Year
      ended December 31, 2007
                  
                  Cost
                  
                  
                  Accumulated
                    depletion
      and
                    depreciation
                  
                  Net
      Book
                    valueOil
      and natural gas properties
                  
                  $
                  2,870,191
                  
                  
                  $
                  1,116,281
                  
                  $
                  1,753,910Midstream
      assets
                  
                  
                  790,434
                  
                  
                  
                  63,763
                  
                  
                  726,671Office
      equipment
                  
                  
                  40,936
                  
                  
                  
                  11,246
                  
                  
                  29,690Total
                  
                  $
                  3,701,561
                  
                  
                  $
                  1,191,290
                  
                  $
                  2,510,271
  Provident
Energy 2008 Financial Statements and Notes
 - 14
-
 
 Costs
associated with unproved properties and major development projects excluded from
costs subject to depletion as at December 31, 2008 totaled $93.1 million
(December 31, 2007 - $137.7 million).  Midstream assets include $41.8
million (2007 - $35.9 million) for products required for line-fill and cavern
bottoms.
 
 An
impairment test calculation was performed on property, plant and equipment at
December 31, 2008 in which the estimated undiscounted future net cash flows
based on estimated future prices associated with the proved reserves exceeded
the carrying amount of oil and gas property, plant and equipment for each cost
centre.
 
 The
following table outlines prices used in the impairment test at December 31,
2008:
  Oil
                  
                  
                  Gas
                  
                  
                  NGLYear
                  
                  $/bbl
                  
                  
                  $/mcf
                  
                  
                  $/bbl2009
                  
                  $
                  56.95
                  
                  
                  $
                  7.12
                  
                  
                  $
                  51.512010
                  
                  $
                  64.13
                  
                  
                  $
                  7.37
                  
                  
                  $
                  59.632011
                  
                  $
                  70.46
                  
                  
                  $
                  7.64
                  
                  
                  $
                  66.152012
                  
                  $
                  76.25
                  
                  
                  $
                  7.92
                  
                  
                  $
                  71.462013
                  
                  $
                  81.08
                  
                  
                  $
                  8.21
                  
                  
                  $
                  76.75Thereafter
      (1)
                  
                  
                  2
                  %
                  
                  
                  2
                  %
                  
                  
                  2
                  %(1)
      Percentage change represents the increase in each year after 2013 to the
      end of the reserve life.
  6.           Intangible
assets
  December
      31, 2008
                  
                  Cost
                  
                  
                  Accumulated
                    amortization
                  
                  Net
      Book
                    valueMidstream
      contracts and customer relationships
                  
                  $
                  183,100
                  
                  
                  
                  37,255
                  
                  $
                  145,845Other
      intangible assets - Midstream
                  
                  
                  16,308
                  
                  
                  
                  3,817
                  
                  
                  12,491Total
                  
                  $
                  199,408
                  
                  
                  $
                  41,072
                  
                  $
                  158,336December
      31, 2007
                  
                  Cost
                  
                  Accumulated
                    amortization
                  
                  Net
      Book
                    valueMidstream
      contracts and customer relationships
                  
                  $
                  183,100
                  
                  
                  $
                  25,049
                  
                  $
                  158,051Other
      intangible assets - Midstream
                  
                  
                  16,308
                  
                  
                  
                  2,566
                  
                  
                  13,742Total
                  
                  $
                  199,408
                  
                  
                  $
                  27,615
                  
                  $
                  171,793
  7.
                Goodwill
 
 Goodwill
represents the excess of the cost of an acquired enterprise over the net of the
amounts assigned to assets acquired and liabilities assumed.  As at
December 31, 2007 Goodwill was comprised of $416.9 million related to
acquisitions in the Canadian oil and gas business and $100.4 million resulted
from the Midstream NGL Acquisition in 2005.
 
 Goodwill
is assessed for impairment at least annually, and if an impairment exists, it
would be charged to income in the period in which the impairment
occurs.  The impairment test includes a comparison of the net book
value of the Trust’s assets, by reporting units, to the estimated fair value of
the reporting unit.  In 2008, Provident engaged the services of a
third-party evaluator to assist in determining fair value.  Valuation
methodologies included discounted cash flow, a transaction-based approach and a
market-based approach, using trading multiples.  Goodwill is not
amortized.
 
 Provident
Energy 2008 Financial Statements and Notes
 - 15
-
 
 The Trust
performed its annual goodwill impairment test in the fourth quarter of 2008 and
determined that the fair value of the Canadian oil and gas production unit was
lower than the respective carrying value, primarily due to increasing economic
uncertainty in the global market and the resulting higher cost of capital
assumptions in the valuation methodologies.  Consequently, a goodwill
impairment, amounting to $416.9 million was recorded.  The impairment
test indicated that the fair value of the Midstream reporting unit was in excess
of the respective carrying value, therefore no write down of midstream-related
goodwill was required.    At December 31, 2008 the goodwill
balance of $100.4 million is related entirely to the Provident Midstream
reporting unit.
 
  8.
                Long-term
      debt
  December
      31, 2008
                  
                  
                  December
      31, 2007Revolving
      term credit facility
                  
                  
                  $
                  504,685
                  
                  
                  $
                  923,996Convertible
      debentures
                  
                  
                  
                  260,994
                  
                  
                  
                  275,638Current
      portion of convertible debentures
                  
                  
                  
                  (24,871
                  )
                  
                  
                  (19,198
                  )236,123
                  
                  
                  
                  256,440Total
                  
                  
                  $
                  740,808
                  
                  
                  $
                  1,180,436
  i)
                Revolving term credit
      facility
  Provident
has a $1,125 million term credit facility (2007 - $1,125 million) with a
syndicate of banks secured by midstream assets and by its Canadian oil and gas
properties.  Provident may draw on the credit facility by way of
Canadian prime rate loans, U.S. base rate loans, banker’s acceptances, letters
of credit or LIBOR loans.  At December 31, 2008, $504.9million was drawn on
this facility.  Included in the carrying value at December 31, 2008
were financing costs of $0.2million.
 
 The terms
of the credit facility have a revolving three year period expiring on May 30,
2011.
 
 At
December 31, 2008 the effective interest rate of the outstanding credit facility
was 3.3percent
(2007 – 5.6 percent).  At December 31, 2008 Provident had $35.2million in letters of
credit outstanding (2007 - $31.6 million) that guarantee Provident’s performance
under certain commercial and other contracts.
 
 
 ii)
                Convertible
      debentures
  The Trust
may elect to satisfy interest and principal obligations by the issue of trust
units.  For the year ended December 31, 2008, $0.1 million of the face
value of debentures were converted to trust units at the election of debenture
holders (2007 - $6.1 million).  Upon maturity in 2008, the Trust
repaid $19.9 million to the holders of its 8.75 percent convertible debentures,
and the balance of the equity component of the 8.75 percent convertible
debentures, amounting to $1.0 million, was transferred to contributed
surplus.  Included in the carrying value at December 31, 2008 were
financing costs of $4.7million.  The
fair value of the convertible debentures at December 31, 2008 approximates the
face value of the instruments.  The following table details each
outstanding convertible debenture.
  As
      at
                  As
      atConvertible
      Debentures
                  
                  December
      31, 2008
                  December
      31, 2007($000s
      except conversion pricing)
                  Carrying
      Value (1)
                  Face
      Value
                  Carrying
      Value (1)
                  Face
      Value
                  Maturity
      Date
                  Conversion
                    Price
      per
                    unit(2)6.5%
      Convertible Debentures
                  $
                  143,212
                  $   149,980
                  140,515
                  $  149,980
                  April
      30, 2011
                  14.756.5%
      Convertible Debentures
                  
                  92,911
                  98,999
                  91,460
                  99,024
                  Aug.
      31, 2012
                  13.758.0%
      Convertible Debentures
                  
                  24,871
                  25,109
                  24,465
                  25,109
                  July
      31, 2009
                  12.008.75%
      Convertible Debentures
                  
                  -
                  -
                  19,198
                  19,931
                  Dec.
      31, 2008
                  11.05$
                  260,994
                  $ 
       274,088
                  $    275,638
                  $  294,044(1)
      Excluding equity component of convertible debentures(2)
      The debentures may be converted into trust units at the option of the
      holder of the debenture at the conversion price per
  unit
  Provident
Energy 2008 Financial Statements and Notes
 - 16
-
  9.
                Asset
      retirement obligation
 
 The
Trust’s asset retirement obligation is based on the Trust’s net ownership in
wells, facilities and the midstream assets and represents management’s estimate
of the costs to abandon and reclaim those wells, facilities and midstream assets
as well as an estimate of the future timing of the costs to be
incurred.   Estimated cash flows have been discounted at the
Trust’s average credit-adjusted risk free rate of sevenpercent and an inflation
rate of two percent has been estimated for future years.
 
 The total
undiscounted amount of future cash flows required to settle asset retirement
obligations related to oil and gas operations is estimated to be $348.5million (2007 - $310.7
million).  Payments to settle oil and gas asset retirement obligations
occur over the operating lives of the assets estimated to be over the next 51
years.
 
 The total
undiscounted amount of future cash flows required to settle the midstream asset
retirement obligations is estimated to be $166.1million (2007 - $166.1
million).  The estimated costs include such activities as dismantling,
demolition and disposal of the facilities as well as remediation and restoration
of the surface land.  Payments to settle the midstream asset
retirement obligations are expected to occur subsequent to the closure of the
facilities and related assets.  Settlement of these obligations is
expected to occur in 25to 41years.
  Year
      ended December 31,($000s)
                  
                  2008
                  
                  
                  2007Carrying
      amount, beginning of year
                  
                  $
                  43,886
                  
                  
                  $
                  33,246Acquisitions
                  
                  
                  -
                  
                  
                  
                  2,504Change
      in estimate
                  
                  
                  15,759
                  
                  
                  
                  7,127Increase
      in liabilities incurred during the year
                  
                  
                  1,729
                  
                  
                  
                  2,221Settlement
      of liabilities during the year
                  
                  
                  (6,381
                  )
                  
                  
                  (4,062
                  )Decrease
      in liabilities due to disposition
                  
                  
                  -
                  
                  
                  
                  (654
                  )Accretion
      of liability
                  
                  
                  4,439
                  
                  
                  
                  3,504Carrying
      amount, end of year
                  
                  $
                  59,432
                  
                  
                  $
                  43,886
  Provident
funds a cash reserve for future site reclamation by paying $0.30 per barrel of
oil equivalent produced on a 6:1 basis into a segregated cash
account.  Actual expenditures are then funded from the cash in this
account.  The cash account has been depleted since 2006 as actual
expenditures have exceeded contributions to the reserve.
 
  10.
                Unitholders’
      contributions
  The Trust
has authorized capital of an unlimited number of common voting trust
units.
 
 Trust
units are redeemable at any time on demand by the holders
thereof.  Upon receipt of a redemption request by the Trust, the
holder is entitled to receive a price per trust unit (the “Market Redemption
Price”) equal to the lesser of:  (i) 90 percent of the simple average
of the closing 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 surrendered for
redemption; and (ii) 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
surrendered for redemption.
 
 The
aggregate Market Redemption Price payable by the Trust in respect of any trust
units surrendered for redemption during any calendar month shall be satisfied by
way of a cash payment on the last day of the following month.  Total
cash payments for redemption are limited to an annual maximum of
$250,000.  Any excess over the maximum may be satisfied by
distributing notes having an aggregate principal amount equal to the aggregate
Market Redemption Price of the trust units tendered for redemption.
 
 Provident
Energy 2008 Financial Statements and Notes
 - 17
-
 
 i)
                2008
      activity
  In 2008,
the Trust issued 6.5 million units related to Provident’s DRIP program,
conversion of convertible debentures to units and units issued pursuant to
Provident’s Unit Option Plan.  The increase in unitholders’
contributions associated with these activities was $55.7 million.
 
 ii)
                2007
      activity
  In 2007,
the Trust issued 29,313,727 trust units at a price of $12.75 per unit for total
proceeds of $373.8 million ($354.6 million net of issue
costs).  Proceeds from the issue were used to fund the Capitol
acquisition, which closed on June 19, 2007.
 
 On
December 3, 2007 the Trust issued 6.3 million units (at an ascribed value of
$76.6 million) as part of the consideration to acquire the outstanding shares of
Triwest Energy Inc.
 
 In 2007,
the Trust issued 5.8 million units related to Provident’s DRIP program,
conversion of convertible debentures to units and units issued pursuant to
Provident’s Unit Option Plan. The increase in unitholders’ contributions
associated with these activities was $65.2 million.
  Year
      ended December 31,2008
                  
                  
                  2007Trust
      Units
                  
                  Number
      of
                    units
                  
                  
                  Amount
                    (000s)
                  
                  
                  Number
      of
                    units
                  
                  
                  Amount
                    (000s)Balance
      at beginning of year
                  
                  
                  252,634,773
                  
                  
                  $
                  2,750,374
                  
                  
                  
                  211,228,407
                  
                  
                  $
                  2,254,048Issued
      for cash
                  
                  
                  -
                  
                  
                  
                  -
                  
                  
                  
                  29,313,727
                  
                  
                  
                  373,750Issued
      to acquire Triwest Energy inc.
                  
                  
                  -
                  
                  
                  
                  -
                  
                  
                  
                  6,251,149
                  
                  
                  
                  76,577Issued
      pursuant to unit option plan
                  
                  
                  191,448
                  
                  
                  
                  1,790
                  
                  
                  
                  825,349
                  
                  
                  
                  8,426Issued
      pursuant to the distribution reinvestment plan
                  
                  
                  5,600,810
                  
                  
                  
                  50,667
                  
                  
                  
                  3,941,864
                  
                  
                  
                  45,338To
      be issued pursuant to the distribution reinvestment plan
                  
                  
                  655,142
                  
                  
                  
                  3,171
                  
                  
                  
                  525,822
                  
                  
                  
                  5,153Debenture
      conversions
                  
                  
                  5,616
                  
                  
                  
                  69
                  
                  
                  
                  548,455
                  
                  
                  
                  6,270Unit
      issue costs
                  
                  
                  -
                  
                  
                  
                  -
                  
                  
                  
                  -
                  
                  
                  
                  (19,188
                  )Balance
      at end of year
                  
                  
                  259,087,789
                  
                  
                  $
                  2,806,071
                  
                  
                  
                  252,634,773
                  
                  
                  $
                  2,750,374
  The basic
per trust unit amounts for 2008 were calculated based on the weighted average
number of units outstanding of 255,177,346(2007 – 229,939,158).
The diluted per trust unit amounts for 2008 are calculated including no
additional trust units (2007 – nil) for the dilutive effect of the unit option
plan and the convertible debentures.
 
  11.
                Unit
      based compensation
 
 i)
                Restricted/Performance
      units
  Certain
employees of the Trust are granted restricted trust units (RTUs) and/or
performance trust units (PTUs), both of which entitle the employee to receive
cash compensation in relation to the value of a specific number of underlying
notional trust units.  The grants are based on criteria designed to
recognize the long term value of the employee to the
organization.  RTUs vest evenly over a period of three years
commencing at the grant date.  Payments are made on the anniversary
dates of the RTU to the employees entitled to receive them on the basis of a
cash payment equal to the value of the underlying notional
units.  PTUs vest three years from the date of grant and can be
increased to a maximum of double the PTUs granted or a minimum of nil PTUs
depending on the Trust’s performance vis-à-vis other trusts’ performance based
on certain benchmarks.
  As of
December 31, 2008 there were 1,139,835RTUs and 3,400,330PTUs outstanding (2007 –
849,672 RTUs and 2,478,037 PTUs).  The fair value estimate associated
with the RTUs and PTUs is expensed in the statement of operations over the
vesting period.  At December 31, 2008, $9.4million (2007 - $9.9
million) is included in accounts payable and accrued liabilities for this plan
and $8.6million
(2007 - $12.4 million) is included in other long-term
liabilities.  The following table reconciles the expense recorded for
RTUs and PTUs.
 
 Provident
Energy 2008 Financial Statements and Notes
 - 18
-
  Year
      ended December 31,2008
                  
                  
                  2007Cash
      general and administrative
                  
                  $
                  8,287
                  
                  
                  $
                  1,767Non-cash
      unit based compensation
                    (included
      in general and administrative)
                  
                  
                  (4,117
                  )
                  
                  
                  8,007Production,
      operating and maintenance expense
                  
                  
                  266
                  
                  
                  
                  430$
                  4,436
                  
                  
                  $
                  10,204
  ii)
                Unit option
      plan
  The Trust
option plan (the “Plan”) is administered by the Board of Directors of
Provident.  In October 2005, a restricted/performance unit program
(see (i)) was approved.  This program replaced the unit option
plan.  Unit options in existence continue to be outstanding until
exercised or expired.
 
 At
December 31, 2008, the Trust had 967,026 options outstanding and exercisable
(2007 – 1,279,169)with strike prices
ranging between $10.92and $12.14per unit (2007 – between
$10.49 and $12.14).  The weighted average exercise price was $11.08
per unit (2007 - $11.04)excluding average
potential reductions to the strike prices of $2.14 per unit (2007 -
$1.77).
 
 The
following table reconciles the movement in the contributed surplus
balance.
  Year
      ended December 31,2008
                  
                  
                  2007Contributed
      surplus, beginning of the year
                  
                  $
                  801
                  
                  
                  $
                  1,315Non-cash
      unit based compensation
                    (included
      in general and administrative)
                  
                  
                  -
                  
                  
                  
                  57Benefit
      on options exercised charged to unitholders’ contributions
                  
                  
                  (117
                  )
                  
                  
                  (571
                  )Transferred
      from convertible debentures equity component on
                    maturity
      (see note 8)
                  
                  
                  1,011
                  
                  
                  
                  -Contributed
      surplus, end of year
                  
                  $
                  1,695
                  
                  
                  $
                  801
 
  12.
                Income
      taxes
 
 In 2007,
future income tax expense includes $88.4 million relating to the enactment of
Bill C-52, Budget Implementation Act 2007 by the Canadian
government.  This bill contains legislation to tax publicly traded
trusts including the Trust.  As a result of this legislation, the
Trust is required to record the future tax effect of the temporary differences
on its flow through entities that are expected to reverse subsequent to
2010.
 
 Although
the Trust believes it will be subject to additional tax under the legislation,
the estimated effective tax rate on temporary difference reversals after 2011
may change in future periods.  Future technical interpretations of the
legislation could occur and could materially affect management’s estimate of the
future income tax liability.
 
 The
amount and timing of reversals of temporary differences will also depend on the
Trust’s future operating results, acquisitions and dispositions of assets and
liabilities, and distribution policy.  A significant change in any of
the preceding assumptions could materially affect the Trust’s estimate of the
future tax liability.
 
 The
future income tax liability is comprised of the following:
  Provident
Energy 2008 Financial Statements and Notes
 - 19
-
  Year
      ended December 31,2008
                  
                  
                  2007Property,
      plant and equipment in excess of tax value
                  
                  $
                  378,663
                  
                  
                  $
                  416,319Asset
      retirement obligation
                  
                  
                  (16,863
                  )
                  
                  
                  (13,360
                  )Financial
      derivative instruments
                  
                  
                  (15,123
                  )
                  
                  
                  (52,050
                  )Non-capital
      losses
                  
                  
                  (68,414
                  )
                  
                  
                  (47,318
                  )Other
                  
                  
                  (10,456
                  )
                  
                  
                  (1,502
                  )$
                  267,807
                  
                  
                  $
                  302,089
  The
income tax provision differs from the expected amount calculated by applying the
Trust’s combined federal and provincial/state income tax rate of 30.96percent (2007 – 32.81
percent) as follows:
  Year
      ended December 31,2008
                  
                  
                  2007Expected
      income tax recovery, from continuing operations
                  
                  $
                  (6,135
                  )
                  
                  $
                  (44,030
                  )Increase
      (decrease) resulting from:Future
      income tax expense relating to enactment of Bill C-52,Budget
      Implementation Act 2007
                  
                  
                  -
                  
                  
                  
                  88,352Goodwill
      impairment (permanent difference)
                  
                  
                  124,992
                  
                  
                  
                  -Income
      of the Trust and other
                  
                  
                  (142,169
                  )
                  
                  
                  (64,558
                  )Capital
      taxes
                  
                  
                  3,109
                  
                  
                  
                  3,762Witholding
      tax and other
                  
                  
                  (498
                  )
                  
                  
                  3,425Income
      tax rate differences
                  
                  
                  (10,484
                  )
                  
                  
                  (5,193
                  )Income
      tax recovery, from continuing operations
                  
                  $
                  (31,185
                  )
                  
                  $
                  (18,242
                  )
  13.
                Financial
      instruments
 
 Risk
Management overview
  Provident
has a comprehensive Enterprise Risk Management program that is designed to
identify and manage risks that could negatively affect its business, operations
or results. The program’s activities include risk identification, assessment,
response, control, monitoring and communication.
 
 Provident’s
Risk Management group executes the program with oversight from the Risk
Management Committee (“RMC”), which provides regular reports to the Audit
Committee and Board of Directors.
 
 Provident
has established and implemented Risk Management strategies, policies and limits
that are monitored by Provident’s Risk Management group.  The
derivative instruments the Trust uses include put and call options, costless
collars, participating swaps, and fixed price products that settle against
indexed referenced pricing. Put option contracts effectively create a floor
price for the commodity while allowing for full participation if prices
increase.  Call options are contracts that allow for a commodity to be
sold at a fixed price at the option of the contract holder.  Costless
collars are contracts that provide a floor and a ceiling price to limit the risk
if prices fall and allowing upward participation within a set
range.  Participating swaps are contracts that provide a floor and
also provide a ceiling for a certain percentage of the volume of the
contract.  This type of derivative allows for price protection if the
price falls, while still allowing some participation if the price
increases.  Fixed price swaps are contracts that specify a fixed price
at which a certain volume of product will be bought or sold at in the
future.
 
 The Risk
Management group monitors risk exposure by generating and reviewing
mark-to-market reports and counterparty credit exposure of Provident’s
outstanding derivative contracts.  Additional monitoring activities
include reviewing available derivative positions, regulatory changes and bank
and analyst reports.
 
 Provident
Energy 2008 Financial Statements and Notes
 - 20
-
 
 Provident’s
commodity price risk management program utilizes derivative instruments to
provide for insurance against lower commodity prices and product margins, as
well as fluctuating interest and foreign exchange rates.  The program
is designed to stabilize cash flows in order to support cash distributions,
capital programs and bank financing.  The risk management strategy
protects a percentage of Provident’s oil and natural gas production against a
decline in commodity prices.  Provident seeks to use products that
allow participation in a rising commodity price environment where possible and
economic.  The program provides price stabilization and protection of
a percentage of inventory values and fractionation spread margin associated with
the midstream business unit.  As well, the Provident risk management
strategy reduces foreign exchange risk due to the exposure arising from the
conversion of U.S. dollars into Canadian dollars.
 
 Fair
Values
  The fair
values of financial instruments are determined by reference to independent
monthly forward settlement prices, interest rate yield curves, currency rates,
and volatility rates at the period-end dates.  All of Provident’s
financial instruments are executed in liquid markets.
  Management
believes that financial markets currently provide adequate liquidity through
price discovery and active credit-worthy counterparties for Provident to
continue to execute the program in 2009.
  As
      at December 31, 2008
                  
                  Held
      for
                    Trading
                  
                  
                  Available
                    for
      Sale
                  
                  
                  Loans
      and
                    Receivables
                  
                  
                  Other
                    Liabilities
                  
                  
                  Total
                    Carrying
                    ValueAssetsAccounts
      receivable
                  
                  $
                  -
                  
                  
                  $
                  -
                  
                  
                  $
                  244,485
                  
                  
                  $
                  -
                  
                  
                  $
                  244,485Financial
      derivative instruments
                    -
      current assets
                  
                  
                  16,708
                  
                  
                  
                  -
                  
                  
                  
                  -
                  
                  
                  
                  -
                  
                  
                  
                  16,708-
      long term assets
                  
                  
                  735
                  
                  
                  
                  -
                  
                  
                  
                  -
                  
                  
                  
                  -
                  
                  
                  
                  735Investments
      and other long-term assets
                  
                  
                  -
                  
                  
                  
                  1,972
                  
                  
                  
                  12,246
                  
                  
                  
                  -
                  
                  
                  
                  14,218$
                  17,443
                  
                  
                  $
                  1,972
                  
                  
                  $
                  256,731
                  
                  
                  $
                  -
                  
                  
                  $
                  276,146LiabilitiesAccounts
      payable and accrued liabilities
                  
                  $
                  -
                  
                  
                  $
                  -
                  
                  
                  $
                  -
                  
                  
                  $
                  244,031
                  
                  
                  $
                  244,031Cash
      distributions payable
                  
                  
                  -
                  
                  
                  
                  -
                  
                  
                  
                  -
                  
                  
                  
                  20,088
                  
                  
                  
                  20,088Current
      portion of convertible debentures
                  
                  
                  -
                  
                  
                  
                  -
                  
                  
                  
                  -
                  
                  
                  
                  24,871
                  
                  
                  
                  24,871Financial
      derivative instruments
                    -
      current liabilities
                  
                  
                  13,693
                  
                  
                  
                  -
                  
                  
                  
                  -
                  
                  
                  
                  -
                  
                  
                  
                  13,693Long-term
      debt - revolving term credit facilities
                  
                  
                  -
                  
                  
                  
                  -
                  
                  
                  
                  -
                  
                  
                  
                  504,685
                  
                  
                  
                  504,685Long-term
      debt - convertible debentures
                  
                  
                  -
                  
                  
                  
                  -
                  
                  
                  
                  -
                  
                  
                  
                  236,123
                  
                  
                  
                  236,123Financial
      derivative instruments
                    -
      long -term liabilities
                  
                  
                  58,420
                  
                  
                  
                  -
                  
                  
                  
                  -
                  
                  
                  
                  -
                  
                  
                  
                  58,420Other
      long-term liabilities
                  
                  
                  -
                  
                  
                  
                  -
                  
                  
                  
                  -
                  
                  
                  
                  8,572
                  
                  
                  
                  8,572$
                  72,113
                  
                  
                  $
                  -
                  
                  
                  $
                  -
                  
                  
                  $
                  1,038,370
                  
                  
                  $
                  1,110,483
 
 Except as
disclosed in note 8 in connection with the convertible debentures, there were no
significant differences between the carrying value of these financial
instruments and their estimated fair value as at December 31, 2008.
 
 The
following table is a summary of the net financial derivative instruments
liability:
  As
      at
                  
                  
                  As
      atDecember
      31,
                  
                  
                  December
      31,($000s)
                  
                  2008
                  
                  
                  2007Provident
      UpstreamCrude
      Oil
                  
                  $
                  (12,521
                  )
                  
                  $
                  19,215Natural
      Gas
                  
                  
                  (3,285
                  )
                  
                  
                  (5,901
                  )Provident
      Midstream
                  
                  
                  70,476
                  
                  
                  
                  261,587Corporate
                  
                  
                  -
                  
                  
                  
                  245Total
                  
                  $
                  54,670
                  
                  
                  $
                  275,146
 
 Provident
Energy 2008 Financial Statements and Notes
 - 21
-
 
 Market
Risk
  Market
risk is the risk that the fair value of a financial instrument will fluctuate
because of changes in market prices. Market risk generally comprises of price
risk, currency risk and interest rate risk.
 
 a)
                Price
      risk
  Commodity
Price Risk Management Program
  The
decisions to enter into financial derivative positions and to execute the risk
management strategy are made by senior officers of Provident who are also
members of the RMC. The RMC receives input and commodity expertise from each
business unit in the decision making process. Strategies are selected based on
their ability to help Provident provide stable cash flow and distributions per
unit rather than to simply lock in a specific price per barrel of oil or cubic
foot of natural gas.
  Oil
and Natural Gas
  Provident’s
risk management program employs derivative instruments, such as puts,
participating swaps, costless collars and fixed price swaps, to protect a floor
level of Provident’s revenue on a portion of the oil and gas sold.  At
the same time, these instruments may enable Provident to retain various levels
of participation to the extent oil and gas prices rise.  Provident may
also use derivative instruments for its oil and natural gas business line to
protect acquisition economics.
 
 The major
identified risks for the oil and natural gas business line are commodity price
volatility and market location and product quality differentials. Provident
addresses these risks using a risk management program designed to protect a
portion of its cash flow in order to support continued unitholder distributions,
capital programs and bank financing.
  Midstream
  Commodity
price volatility and market location differentials also affect the Midstream
business. In addition, Midstream is exposed to possible price declines between
the time Provident purchases natural gas liquid (NGL) feedstock and sells NGL
products, and to narrowing frac spread ratios. Frac spread ratio is the ratio
between crude oil prices and natural gas prices. There is also a differential
between NGL product prices (propane, butane and condensate) and crude oil
prices.
 
 Provident
responds to these risks using a risk management program that protects a
margin or floor level of operating income on a portion of its NGL inventory and
production, while retaining some ability to participate in a widening margin
environment.  For the longer-term, Provident uses crude oil contracts
in place of NGLs.  Provident may replace these contracts with NGL
product contracts as market conditions allow. This strategy enables Provident to
mitigate commodity price risk related to its NGL production business up to
approximately five years into the future.
 
 b)
                Currency
      risk
 
 Provident’s
oil, natural gas and NGL sales are exposed to both positive and negative
effects of fluctuations in the Canadian/U.S. exchange rate.  Provident
manages this exposure by matching a significant portion of the cash costs that
it expects with revenues in the same currency.  As well, Provident
uses derivative instruments to manage the U.S. cash requirements of its business
lines.
 
 Provident
regularly sells or purchases forward a portion of expected U.S.
cashflows.  Provident’s strategy also manages the exposure it has to
fluctuations in the U.S./Canadian dollar exchange rate when the underlying
commodity price is based upon a U.S. index price.  Provident may also
use derivative products that provide for protection against a stronger Canadian
dollar, while allowing it to participate if the currency weakens relative to the
U.S. dollar.
  Provident
Energy 2008 Financial Statements and Notes
 - 22
-
 
 c)
                Interest
      rate risk
 
 The
Trust’s revolving term credit facilities bear interest at a floating
rate.  Using debt levels as at December 31, 2008, an increase/decrease
of 50 basis points in the lender’s base rate would result in an
increase/decrease of annual interest expense of approximately $2.5million.
  Financial
derivative sensitivity analysis
  The
following table shows the impact on unrealized gain (loss) on financial
derivative instruments if the underlying risk variables of the financial
derivative instruments changed by a specified amount, with other variables held
constant.
  Cdn
      (000's)
                  
                  
                  +
      Change
                  
                  
                  -
      ChangeProvident
      UpstreamCrude
      Oil
                  (WTI
      +/- $10.00 per bbl)
                  
                  $
                  (6,222
                  )
                  
                  $
                  6,836Natural
      Gas
                  (AECO
      +/- $1.00 per gj)
                  
                  
                  (1,776
                  )
                  
                  
                  1,951Provident
      MidstreamFrac
      spread relatedCrude
      Oil
                  (WTI
      +/- $10.00 per bbl)
                  
                  
                  (109,232
                  )
                  
                  
                  109,841Natural
      Gas
                  (AECO
      +/- $1.00 per gj)
                  
                  
                  67,264
                  
                  
                  
                  (67,075
                  )NGL's
      (includes propane, butane, natural gasoline)
                  (Belvieu
      +/- US $0.15 per gal)
                  
                  
                  (413
                  )
                  
                  
                  413Foreign
      Exchange ($U.S. vs $Cdn)
                  (FX
      rate +/- $ 0.01)
                  
                  
                  (2,299
                  )
                  
                  
                  2,283Inventory/margin
      relatedCrude
      Oil
                  (WTI
      +/- $10.00 per bbl)
                  
                  
                  (13,872
                  )
                  
                  
                  13,885Natural
      Gas
                  (AECO
      +/- $1.00 per gj)
                  
                  
                  (78
                  )
                  
                  
                  78NGL's
      (includes propane, butane, natural gasoline)
                  (Belvieu
      +/- US $0.15 per gal)
                  
                  
                  11,645
                  
                  
                  
                  (11,625
                  )
  Liquidity
Risk
  Liquidity
risk is the risk the Trust will not be able to meet its financial obligations as
they come due. The Trust’s approach to managing liquidity risk is to ensure that
it always has sufficient cash and credit facilities to meet its obligations when
due, without incurring unacceptable losses or damage to the Trust’s
reputation.
 
 Management
typically forecasts cash flows for a period of twelve months to identify
financing requirements. These requirements are then addressed through a
combination of committed and demand credit facilities and access to capital
markets, as discussed in note 14.
 
 The
following table outlines the timing of the cash outflows relating to financial
liabilities.
  As
      at December 31, 2008
                  
                  Payment
      due by period($000s)
                  
                  Total
                  
                  
                  Less
      than
                    1
      year
                  
                  
                  1
      to 3 years
                  
                  
                  4
      to 5 yearsAccounts
      payable and accrued liabilities
                  
                  $
                  244,031
                  
                  
                  $
                  244,031
                  
                  
                  $
                  -
                  
                  
                  $
                  -Cash
      distributions payable
                  
                  
                  20,088
                  
                  
                  
                  20,088
                  
                  
                  
                  -
                  
                  
                  
                  -Current
      portion of convertible debentures (2)
                  
                  
                  26,281
                  
                  
                  
                  26,281
                  
                  
                  
                  -
                  
                  
                  
                  -Financial
      derivative instruments - current
                  
                  
                  13,693
                  
                  
                  
                  13,693
                  
                  
                  
                  -
                  
                  
                  
                  -Long-term
      debt - revolving term credit facilities (1)
      (2)
                  
                  
                  548,761
                  
                  
                  
                  16,784
                  
                  
                  
                  531,977
                  
                  
                  
                  -Long-term
      debt - convertible debentures(2)
                  
                  
                  295,322
                  
                  
                  
                  16,184
                  
                  
                  
                  175,849
                  
                  
                  
                  103,289Long-term
      financial derivative instruments
                  
                  
                  58,420
                  
                  
                  
                  -
                  
                  
                  
                  43,147
                  
                  
                  
                  15,273Other
      long-term liabilities
                  
                  
                  8,572
                  
                  
                  
                  -
                  
                  
                  
                  8,572
                  
                  
                  
                  -Total
                  
                  $
                  1,215,168
                  
                  
                  $
                  337,061
                  
                  
                  $
                  759,545
                  
                  
                  $
                  118,562(1)The
      terms of the Canadian credit facility have a revolving three year period
      expiring on May 30, 2011.(2)Includes
      associated interest and principal payments.
 Provident
Energy 2008 Financial Statements and Notes
 - 23
-
 
 Credit
Risk
  Provident's
Credit Policy governs the activities undertaken to mitigate the risks associated
with counterparty (customer) non-payment.  The Policy requires a
formal credit review for counterparties entering into a commodity contract with
Provident.  This review determines an approved credit
limit.  Activities undertaken include regular monitoring of
counterparty exposures to approved credit limits, financial review of all active
counterparties, utilizing master netting arrangements and International Swap
Dealers Association (ISDA) agreements and obtaining financial assurances where
warranted.  Financial assurances include guarantees, letters of credit and
cash.  In addition, Provident has a diversified base of
creditors.
 
 Substantially
all of the Trust's accounts receivable are due from customers and joint venture
partners in the oil and gas and midstream services and marketing industries and
are subject to credit risk. The Trust partially mitigates associated credit risk
by limiting transactions with certain counterparties to limits imposed by the
Trust based on management’s assessment of the creditworthiness of such
counterparties.  The carrying value of accounts receivable reflects
management's assessment of the associated credit risks.
 
 Financial
Derivative Instruments – 2008 Activity
  i)
                Provident
      Upstream
  a)
                Crude
  oil
  In 2008,
Provident paid $11.1 million (2007 - $7.9 million) to settle various oil market
based contracts on an aggregate volume of 1.6 million barrels (2007 – 1.6
million barrels).  The estimated value of contracts in place if
settled at market prices at December 31, 2008 would have resulted in an
opportunity gain of $12.5 million (2007 – $19.2 million opportunity
cost).
 
 b)
                Natural
    Gas
  In 2008,
Provident received nil (2007 - $9.6 million) to settle various natural gas
market based contracts on an aggregate of 10.9 million gigajoules (“gj”) (2007 –
16.7 million gj’s).  The estimated value of contracts in place if
settled at market prices at December 31, 2008 would have resulted in an
opportunity gain of $3.3 million (2007 – $5.8 million).
  ii)
                Provident
      Midstream
  In 2008,
Provident paid $135.6 million (2007 – received $17.9 million) to settle
Midstream oil market based contracts on an aggregate volume of 4.2 million
barrels (2007 - 1.2 million barrels) and paid $17.0 million (2007 - $48.7
million) to settle Midstream natural gas market based contracts on an aggregate
volume of 26.8 million gj’s (2007 – 25.3 million gj’s).  In addition,
Provident received $25.9million
(2007 – paid $48.2 million) to settle Midstream NGL market based contracts on an
aggregate volume of 2.3million
barrels (2007 – 7.2 million barrels).
 
 Provident
also received $5.4 million (2007 - $4.6 million) to settle Midstream-related
foreign exchange contracts, and received $2.4 million (2007 – nil) to settle
various electricity-based contracts.  The estimated value of contracts
in place if settled at market prices at December 31, 2008 would have resulted in
an opportunity cost of $70.5 million (2007 –  $261.6
million).
 iii)
                  Corporate
  a)
                Foreign exchange
      contracts
  In 2008,
Provident received $26.8 million to settle various corporate-related foreign
exchange contracts (2007 - $1.3 million).  Realized gains and losses
on corporate-related foreign exchange contracts are included in foreign exchange
(gain) loss and other on the consolidated statement of operations and are
allocated to the reporting segments for segmented reporting
purposes.  The
  Provident
Energy 2008 Financial Statements and Notes
 - 24
-
 
 estimated
value of contracts in place if settled at foreign exchange rates at December 31,
2008 would have resulted in an opportunity cost of nil (2007 – $0.1
million).
  The
contracts in place at December 31, 2008 are summarized in the following
tables:
  Provident
      UpstreamVolumeYear
                  Product
                  (Buy)/Sell
                  Terms
                  Effective
      Period2009
                  Crude
      Oil
                  2,000
                  
                  Bpd
                  WCS
      Blend at 80% of US$ WTI
                  January
      1 - March 312,283
                  
                  Bpd
                  Participating
      Swap US $62.36 per bbl (Participation Range 52% to 90% above the floor
      price)
                  January
      1 - December 31Natural
      Gas
                  5,000
                  
                  Gjpd
                  Puts
      Cdn $9.29 per gj
                  January
      1 - March 314,871
                  
                  Gjpd
                  Participating
      Swap Cdn $6.93 per gj (Participation Range 20% to 95% above the floor
      price)
                  January
      1 - December 31
 Provident
      MidstreamVolumeYear
                  Product
                  (Buy)/Sell
                  Terms
                  Effective
      Period2009
                  Crude
      Oil
                  7,038
                  
                  Bpd
                  Cdn
      $74.20 per bbl
                  January
      1 - December 31750
                  
                  Bpd
                  US
      $65.97 per bbl
                  January
      1 - December 312,973
                  
                  Bpd
                  US
      $85.16 per bbl(12)
                  January
      1 - December 31(1,052
                  )
                  Bpd
                  Cdn
      $70.21 per bbl(10)
                  January
      1 - November 30(420
                  )
                  Bpd
                  US
      $88.30 per bbl (9)
                  January
      1 - March 31323
                  
                  Bpd
                  US
      $57.78 per bbl (11)
                  May
      1 - May 312,748
                  
                  Bpd
                  Costless
      Collar US $65.27 floor, US $70.23 ceiling
                  January
      1 - December 31621
                  
                  Bpd
                  Participating
      Swap Cdn $78.27 per bbl (Average Participation 38% above the floor
      price)
                  September
      1 - December 311,052
                  
                  Bpd
                  Participating
      Swap US $71.31 per bbl (Average Participation 54% above the floor
      price)
                  July
      1 - November 30Natural
      Gas
                  (60,255
                  )
                  Gjpd
                  Cdn
      $8.15 per gj
                  January
      1 - December 312,500
                  
                  Gjpd
                  Cdn
      $6.56 per gj (11)
                  January
      1 - January 31(3,477
                  )
                  Gjpd
                  Participating
      Swap Cdn $7.86 per gj (Average Participation 33% below the ceiling
      price)
                  July
      1 - December 31(2,810
                  )
                  Gjpd
                  Costless
      Collar Cdn $6.20 floor, Cdn $7.10 ceiling
                  September
      1 - October 31Propane
                  760
                  
                  Bpd
                  US
      $1.32 per gallon(5)
      (11)
                  January
      1 - March 31600
                  
                  Bpd
                  US
      $1.265 per gallon(9)
                  January
      1 - March 31333
                  
                  Bpd
                  US
      $0.99 per gallon(6)
      (11)
                  January
      1 - March 31Natural
      Gasoline
                  (2,973
                  )
                  Bpd
                  US
      $1.74 per gallon(12)
                  January
      1 - December 31Normal
      Butane
                  (1,473
                  )
                  Bpd
                  US
      $0.76 per gallon(12)
                  April
      1 - December 31Foreign
      Exchange
                  
                  
                  Sell
      US $6,432,441 per month @ 1.1117(13)
                  January
      1 - December 31Sell
      US $1,055,833 per month @ 1.099 (13)
                  January
      1 - June 30Sell
      US $1,972,561 per month @ 1.0244(13)
                  July
      1 - August 31Sell
      US $596,166 per month @ 0.9815 (13)
                  July
      1 - October 31Sell
      US $1,686,650 per month @ 0.9622 (13)
                  September
      1 - October 31Sell
      US $1,809,600 per month @ 1.0098(13)
                  November
      1 - November 30
  
 Provident
Energy 2008 Financial Statements and Notes
 - 25
-
 Provident
      Midstream cont'd.VolumeYear
                  Product
                  (Buy)/Sell
                  Terms
                  Effective
      Period2010
                  Crude
      Oil
                  6,238
                  
                  Bpd
                  Cdn
      $73.19 per bbl
                  January
      1 - December 31500
                  
                  Bpd
                  US
      $66.65 per bbl
                  January
      1 - December 311,750
                  
                  Bpd
                  Costless
      Collar US $61.63 floor, US $66.56 ceiling
                  January
      1 - December 31464
                  
                  Bpd
                  Participating
      Swap Cdn $77.01 per bbl (Average Participation 37% above the floor
      price)
                  January
      1 - December 31860
                  
                  Bpd
                  Participating
      Swap US $74.89 per bbl (Average Participation 48% above the floor
      price)
                  January
      1 - December 31Natural
      Gas
                  (47,181)
                  
                  Gjpd
                  Cdn
      $7.83 per gj
                  January
      1 - December 31(5,756)
                  
                  Gjpd
                  Participating
      Swap Cdn $7.77 per gj (Average Participation 28% below the ceiling
      price)
                  January
      1 - December 31Normal
      Butane
                  (1,500)
                  
                  Bpd
                  US
      $0.76 per gallon(12)
                  January
      1 - March 31Foreign
      Exchange
                  
                  
                  Sell
      US $4,773,059 per month @ 1.1110(13)
                  January
      1 - December 31Sell
      US $582,821 per month @ 1.0159(13)
                  January
      1 - August 31Sell
      US $1,420,921 per month @ 0.9781 (13)
                  July
      1 - August 31Sell
      US $587,903 per month @ 1.0165(13)
                  July
      1 - November 30Sell
      US $2,254,103 per month @ 0.9578 (13)
                  September
      1 - October 31Sell
      US $2,394,058 per month @ 1.0154 (13)
                  September
      1 - November 30Sell
      US $629,673 per month @ 1.0165 (13)
                  November
      1 - December 312011
                  Crude
      Oil
                  5,534
                  
                  Bpd
                  Cdn
      $71.73 per bbl
                  January
      1 - December 311,005
                  
                  Bpd
                  Costless
      Collar US $60.64 floor, US $73.45 ceiling
                  January
      1 - September 30416
                  
                  Bpd
                  Participating
      Swap Cdn $84.38 per bbl (Average Participation 25% above the floor
      price)
                  October
      1 - December 31250
                  
                  Bpd
                  Participating
      Swap US $63.00 per bbl (Average Participation 64% above the floor
      price)
                  January
      1 - December 31Natural
      Gas
                  (37,595)
                  
                  Gjpd
                  Cdn
      $7.32 per gj
                  January
      1 - December 31(2,337)
                  
                  Gjpd
                  Participating
      Swap Cdn $8.28 per gj (Average Participation 25% below the ceiling
      price)
                  October
      1 - December 31Foreign
      Exchange
                  
                  
                  Sell
      US $479,063 per month @ 0.9725(13)
                  January
      1 - December 31Sell
      US $980,417 per month @ 1.0805 (13)
                  January
      1 - June 30Sell
      US $3,588,000 per month @ 1.0918(13)
                  July
      1 - September 302012
                  Crude
      Oil
                  3,637
                  
                  Bpd
                  Cdn
      $72.57 per bbl
                  January
      1 - December 311,445
                  
                  Bpd
                  Participating
      Swap Cdn $85.19 per bbl (Average Participation 27% above the floor
      price)
                  February
      1 - December 311,352
                  
                  Bpd
                  Participating
      Swap US $72.22 per bbl (Average Participation 51% above the floor
      price)
                  March
      1 - December 31Natural
      Gas
                  (25,717)
                  
                  Gjpd
                  Cdn
      $7.24 per gj
                  January
      1 - December 31(9,318)
                  
                  Gjpd
                  Participating
      Swap Cdn $8.55 per gj (Average Participation 28% below the ceiling
      price)
                  February
      1 - December 31Foreign
      Exchange
                  
                  
                  Sell
      US $2,016,783 per month @ 1.0119(13)
                  March
      1 - March 31Sell
      US $1,041,721 per month @ 0.9413(13)
                  April
      1 - October 31Sell
      US $681,260 per month @ 0.9850 (13)
                  May
      1 - October 31Sell
      US $1,437,986 per month @ 0.9659 (13)
                  July
      1 - December 31Sell
      US $1,634,227 per month @ 0.9829 (13)
                  October
      1 - December 31Sell
      US $1,420,538 per month @ 0.9995(13)
                  November
      1 - December 312013
                  Crude
      Oil
                  250
                  
                  Bpd
                  Cdn
      $75.32 per bbl
                  January
      1 - January 311,250
                  
                  Bpd
                  Participating
      Swap Cdn $84.90 per bbl (Average Participation 25% above the floor
      price)
                  January
      1 - March 31758
                  
                  Bpd
                  Participating
      Swap US $85.62 per bbl (Average Participation 30% above the floor
      price)
                  January
      1 - March 31Natural
      Gas
                  (7,025)
                  
                  Gjpd
                  Cdn
      $7.19 per gj
                  January
      1 - January 31(9,524)
                  
                  Gjpd
                  Participating
      Swap Cdn $8.87 per gj (Average Participation 22% below the ceiling
      price)
                  January
      1 - March 31Foreign
      Exchange
                  
                  
                  Sell
      US $1,651,990 per month @ 0.9829(13)
                  January
      1 - January 31Sell
      US $1,397,250 per month @ 0.9995(13)
                  January
      1 - March 31(1)The
      above table represents a number of transactions entered into over an
      extended period of time.(2)Natural
      gas contracts are settled against AECO monthly index.(3)Crude
      Oil contracts are settled against NYMEX WTI calendar
    average.(4)WCS
      contracts are settled against NYMEX WTI calendar average plus the monthly
      index for physical WCS (quoted as a differential to WTI) by NetThruPut
      Inc.(5)Propane
      contracts are settled against Belvieu C3 TET.(6)Propane
      contracts are settled against Conway In-Well C3.(7)Normal
      Butane contracts are settled against Belvieu NC4 TET.(8)Natural
      Gasoline contracts are settled against Belevieu NON-TET Natural
      Gasoline.(9)Conversion
      of Crude Oil BTU contracts to liquids.(10)BTU re-balancing of Crude Oil contracts.(11)Midstream
      inventory price stabilization contracts.(12)Midstream
      margin contracts.(13)
      US Dollar forward contracts are settled against the Bank of Canada noon
      rate average.
  Provident
Energy 2008 Financial Statements and Notes
 - 26
-
 14.
                  Capital management
 Provident
considers its total capital to be comprised of net debt and Unitholders’
Equity.  Net debt is comprised of long-term debt and working capital
surplus, excluding balances for the current portion of financial derivative
instruments.  The balance of these items at December 31, 2008 and
December 31, 2007 was as follows:
 As
      at
                  
                  
                  As
      atDecember
      31,
                  
                  
                  December
      31,($000s)
                  
                  2008
                  
                  
                  2007Working
      capital surplus (1)
                  
                  $
                  (39,041
                  )
                  
                  $
                  (58,732
                  )Long-term
      debt (including current portion)
                  
                  
                  765,679
                  
                  
                  
                  1,199,634Net
      debt
                  
                  
                  726,638
                  
                  
                  
                  1,140,902Unitholders'
      equity
                  
                  
                  1,636,347
                  
                  
                  
                  1,708,665Total
      capitalization
                  
                  $
                  2,362,985
                  
                  
                  $
                  2,849,567Net
      debt to total capitalization
                  
                  
                  31
                  %
                  
                  
                  40
                  %(1)
      The working capital surplus excludes balances for the current portion of
      financial derivative instruments.
  Provident’s
primary objective for managing capital is to maximize long-term Unitholder value
by:
  ·
                providing
      an appropriate return to shareholders relative to the risk of Provident’s
      underlying assets; and
 ·
                ensuring
      financing capacity for Provident’s internal development opportunities and
      acquisitions of energy related assets that are expected to add value to
      our Unitholders.
 
 Provident
makes adjustments to its capital structure based on economic conditions and the
Trust’s planned requirements.  Provident has the ability to adjust its
capital structure by issuing new equity or debt, controlling the amount it
returns to unitholders, and making adjustments to its capital expenditure
program.  Provident relies on cash flow from operations, external
lines of credit and access to equity markets to fund capital programs and
acquisitions.
 
 The Trust
is subject to certain capital growth restrictions as a result of the Canadian
trust tax legislation passed in June 2007 and effective January 1,
2011.  The restrictions provide that “normal growth” would include
equity growth within certain “safe harbour” limits, measured by reference to the
Trust’s market capitalization as of the end of trading on October 31,
2006.  These rules limit the amount of Unitholders’ capital that can
be issued by the Trust in each of the next two years, as follows:
  ($
      billions)
                  
                  Annual
                  
                  
                  CumulativeNormal
      growth capital allowed in:2009(1)
                  
                  
                  0.6
                  
                  
                  
                  2.32010
                  
                  
                  0.5
                  
                  
                  
                  2.8(1)The
      Trust's allowed growth capital prior to 2009 was approximately $1.7
      billion.
 
 If the
maximum equity growth allowed is exceeded, the Trust may be subject to trust
taxation prior to 2011.  In 2007 and 2008, the Trust issued equity
amounting to $552.0million.
 
  15.
                Discontinued
      operations (USOGP)
 
 In
February 2008, the Trust announced a strategic process respecting the decision
to dispose of the operations that comprise the United States oil and natural gas
production (USOGP) business.  Effective in the first quarter of 2008,
Provident’s USOGP business is accounted for as discontinued operations and
comparative figures have been reclassified to conform with this
presentation.
 
 Provident
Energy 2008 Financial Statements and Notes
 - 27
-
 
 In June
2008, the Trust sold a portion of the USOGP business, consisting of its 22
percent interest in BreitBurn Energy Partners, L.P. (MLP) and its 96 percent
interest in BreitBurn GP LLC, for cash proceeds, net of transaction costs, of
U.S. $342.2 million.  The Trust has recorded a gain on sale of $187.9
million and $127.7 million in current tax expense related to this
transaction.  Also recorded was a realized foreign exchange loss of
$30.3 million, representing the recognition of the related portion of the
foreign exchange loss in accumulated other comprehensive income, which was
generated since inception in 2006.  These amounts are recorded as part
of net income from discontinued operations for the year ended December 31,
2008.
 
 In August
2008, the Trust sold the remaining portion of the USOGP business, comprised of
an approximate 96 percent interest in BreitBurn Energy Company L.P., for total
consideration of U.S. $300.4 million, consisting of cash proceeds, net of
transaction costs, of U.S. $290.4 million and a U.S. $10 million
note.  The Trust has recorded a gain on sale of $75.7 million and
$66.9 million in current tax expense related to this
transaction.  Also recorded was a realized foreign exchange loss of
$26.8 million, representing the recognition of the related portion of the
foreign exchange loss in accumulated other comprehensive income, which was
generated since acquisition in 2004.  These amounts are recorded as
part of net income from discontinued operations for the year ended December 31,
2008.
 
 During
2008, the Trust made tax installment payments for the amounts relating to the
sales of the MLP, BreitBurn GP LLC and BreitBurn Energy Company
L.P.
 
 Quicksilver
Resources Inc. ("Quicksilver") filed a lawsuit on October 31, 2008 against the
MLP, certain of its directors (including three Provident nominees), and
Provident.  The claim relates to a transaction between the MLP and
Quicksilver and certain other MLP matters. Quicksilver alleges, among other
things, that it was induced to enter into a contribution agreement pursuant to
which it contributed assets to the MLP by false representations as to
Provident’s relationship with the MLP. The transaction involved the issuance by
the MLP to Quicksilver of approximately U.S.$700 million of units of the MLP.
The litigation is in its very early stages, and it is not possible at this time
to assess the potential exposure of Provident in the event of an adverse
verdict. Provident believes the claims made against it in the lawsuit are
without merit and will vigorously defend itself and its named director nominees
against these claims.
 
 The
following tables show the net assets of discontinued operations and information
about net income from USOGP.
  As
      at
                  
                  
                  As
      atBalance
      sheets
                  
                  December
      31,
                  
                  
                  December
      31,Canadian
      dollars (000s)
                  
                  2008
                  
                  
                  2007AssetsCurrent
      assets
                  
                  $
                  -
                  
                  
                  $
                  93,578Property,
      plant and equipment
                  
                  
                  -
                  
                  
                  
                  2,008,549Other
      long-term assets
                  
                  
                  -
                  
                  
                  
                  19,055-
                  
                  
                  
                  2,027,604$
                  -
                  
                  
                  $
                  2,121,182LiabilitiesCurrent
      liabilitiesAccounts
      payable and accrued liabilities
                  
                  $
                  -
                  
                  
                  $
                  77,244Financial
      derivative instruments
                  
                  
                  -
                  
                  
                  
                  37,437-
                  
                  
                  
                  114,681Long-term
      debt - revolving term credit facilities
                  
                  
                  -
                  
                  
                  
                  368,836Long-term
      financial derivative instruments
                  
                  
                  -
                  
                  
                  
                  66,382Asset
      retirement obligation and other long-term liabilities
                  
                  
                  -
                  
                  
                  
                  45,373Future
      income taxes
                  
                  
                  -
                  
                  
                  
                  147,911-
                  
                  
                  
                  628,502Non-controlling
      interests
                  
                  
                  -
                  
                  
                  
                  1,100,136Net
      Assets - discontinued operations
                  
                  $
                  -
                  
                  
                  $
                  277,863
  Provident
Energy 2008 Financial Statements and Notes
 - 28
-
  Net
      income from discontinued operations
                  
                  Year
      ended December 31,Canadian
      dollars (000's)
                  
                  2008
                  
                  
                  2007Revenue
                  
                  $
                  303,146
                  
                  
                  $
                  246,760Loss
      from discontinued operations before taxes, non-controllinginterests,
      dilution gain and impact of sale of discontinued
operations
                  
                  
                  (237,233
                  )
                  
                  
                  (90,748
                  )Dilution
      gain
                  
                  
                  -
                  
                  
                  
                  260,324Gain
      on sale of discontinued operations
                  
                  
                  263,618
                  
                  
                  
                  -Foreign
      exchange loss related to sale of discontinued operations
                  
                  
                  (57,062
                  )
                  
                  
                  -Current
      and withholding tax expense
                  
                  
                  (178,708
                  )
                  
                  
                  (10
                  )Future
      income tax recovery (expense)
                  
                  
                  151,975
                  
                  
                  
                  (58,843
                  )Non-controlling
      interests
                  
                  
                  203,434
                  
                  
                  
                  35,666Net
      income from discontinued operations
                  
                  $
                  146,024
                  
                  
                  $
                  146,389
  
 16.
                Commitments
 
 Provident
has office lease commitments that extend through June 2022.  Future
minimum lease payments for the following five years are:  2009 - $8.7
million; 2010 - $8.5 million; 2011 - $8.5 million; 2012 - $8.8 million, and 2013
- $9.0 million.
 
 In
relation to the midstream services and marketing segment, Provident is committed
to minimum lease payments under the terms of various rail tank car leases for
the following five years:  2009 – $9.3 million; 2010 – $7.0 million;
2011 – $5.6 million; 2012 – $3.1 million and 2013 - $0.8
million.  Additionally, under an arrangement to use a third party
interest in the Younger plant, Provident has a commitment to make payments
calculated with reference to a number of variables including return on
capital.  Payments for the next five years are estimated as
follows:  2009 - $4.3 million; 2010 - $4.1 million; 2011 – $3.9
million; 2012 - $3.8 million and 2013 - $3.6 million.
 
  17.
                Segmented
      information
 
 The
Trust’s business activities are conducted through two business segments:
Canadian oil and natural gas production (“COGP” or “Provident Upstream”) and
Provident Midstream.
 
 Provident
Upstream includes exploitation, development and production of crude oil and
natural gas reserves.  Provident Midstream includes processing,
extraction, transportation, loading and storage of natural gas liquids, and
marketing of natural gas liquids.
 
 Geographically
the Trust operates in Canada in the oil and gas production business segment and
in Canada and the USA in the Midstream business.
  
 Provident
Energy 2008 Financial Statements and Notes
 - 29
-
 
 Year
      ended December 31, 2008Provident
                  
                  
                  ProvidentUpstream
                  
                  
                  Midstream
      (1)
                  
                  
                  TotalRevenueGross
      production revenue
                  
                  $
                  681,336
                  
                  
                  $
                  -
                  
                  
                  $
                  681,336Royalties
                  
                  
                  (123,140
                  )
                  
                  
                  -
                  
                  
                  
                  (123,140
                  )Product
      sales and service revenue
                  
                  
                  -
                  
                  
                  
                  2,589,518
                  
                  
                  
                  2,589,518Realized loss
      on financial derivative instruments
                  
                  
                  (11,102
                  )
                  
                  
                  (118,917
                  )
                  
                  
                  (130,019
                  )547,094
                  
                  
                  
                  2,470,601
                  
                  
                  
                  3,017,695ExpensesCost of
      goods sold
                  
                  
                  -
                  
                  
                  
                  2,206,427
                  
                  
                  
                  2,206,427Production,
      operating and maintenance
                  
                  
                  138,173
                  
                  
                  
                  14,938
                  
                  
                  
                  153,111Transportation
                  
                  
                  16,320
                  
                  
                  
                  20,800
                  
                  
                  
                  37,120Foreign
      exchange (gain) loss and other
                  
                  
                  2,917
                  
                  
                  
                  (19,853
                  )
                  
                  
                  (16,936
                  )General
      and administrative
                  
                  
                  36,191
                  
                  
                  
                  35,528
                  
                  
                  
                  71,719193,601
                  
                  
                  
                  2,257,840
                  
                  
                  
                  2,451,441Earnings
      before interest, taxes, depletion, depreciation,accretion
      and other non-cash items
                  
                  
                  353,493
                  
                  
                  
                  212,761
                  
                  
                  
                  566,254Other
      revenueUnrealized
      gain (loss) on financial derivative instruments
                  
                  
                  30,230
                  
                  
                  
                  191,238
                  
                  
                  
                  221,468Other
      expensesDepletion,
      depreciation and accretion
                  
                  
                  304,909
                  
                  
                  
                  38,406
                  
                  
                  
                  343,315Goodwill
      impairment
                  
                  
                  416,890
                  
                  
                  
                  -
                  
                  
                  
                  416,890Interest on
      bank debt
                  
                  
                  9,022
                  
                  
                  
                  27,066
                  
                  
                  
                  36,088Interest and
      accretion on convertible debentures
                  
                  
                  4,986
                  
                  
                  
                  14,958
                  
                  
                  
                  19,944Unrealized
      foreign exchange (gain) loss and other
                  
                  
                  4,296
                  
                  
                  
                  (8,188
                  )
                  
                  
                  (3,892
                  )Non-cash unit
      based compensation
                  
                  
                  (2,199
                  )
                  
                  
                  (1,918
                  )
                  
                  
                  (4,117
                  )Internal
      management charge
                  
                  
                  (689
                  )
                  
                  
                  -
                  
                  
                  
                  (689
                  )Capital
      tax expense
                  
                  
                  3,109
                  
                  
                  
                  -
                  
                  
                  
                  3,109Current
      and withholding tax (recovery) expense
                  
                  
                  (212
                  )
                  
                  
                  (4,317
                  )
                  
                  
                  (4,529
                  )Future
      income tax (recovery) expense
                  
                  
                  (50,339
                  )
                  
                  
                  20,574
                  
                  
                  
                  (29,765
                  )689,773
                  
                  
                  
                  86,581
                  
                  
                  
                  776,354Net
      income (loss) for the year from continuing operations
                  
                  $
                  (306,050
                  )
                  
                  $
                  317,418
                  
                  
                  $
                  11,368Net
      income from discontinued operations (note 15)
                  
                  
                  
                  
                  
                  
                  
                  
                  
                  
                  146,024Net
      income for the year
                  
                  
                  
                  
                  
                  
                  
                  
                  
                  $
                  157,392
 (1)
Included in the Provident Midstream segment is product sales and service revenue
of $307.9 million associated with U.S. operations.
 Provident
Energy 2008 Financial Statements and Notes
 - 30
-
 As
      at and for the year ended December 31, 2008Provident
                  
                  
                  ProvidentUpstream
                  
                  
                  Midstream
                  
                  
                  TotalSelected
      balance sheet itemsCapital
      assetsProperty,
      plant and equipment net
                  
                  $
                  1,731,331
                  
                  
                  $
                  749,172
                  
                  
                  $
                  2,480,503Intangible
      assets
                  
                  
                  -
                  
                  
                  
                  158,336
                  
                  
                  
                  158,336Goodwill
                  
                  
                  -
                  
                  
                  
                  100,409
                  
                  
                  
                  100,409Capital
      expendituresCapital
      Expenditures
                  
                  
                  209,147
                  
                  
                  
                  37,800
                  
                  
                  
                  246,947Oil
      and gas property acquisitions, net
                  
                  
                  24,181
                  
                  
                  
                  -
                  
                  
                  
                  24,181Goodwill
      additions (impairments)
                  
                  
                  (416,890
                  )
                  
                  
                  -
                  
                  
                  
                  (416,890
                  )Working
      capitalAccounts
      receivable
                  
                  
                  60,839
                  
                  
                  
                  183,646
                  
                  
                  
                  244,485Petroleum
      product inventory
                  
                  
                  -
                  
                  
                  
                  46,160
                  
                  
                  
                  46,160Accounts
      payable and accrued liabilities
                  
                  
                  114,152
                  
                  
                  
                  129,879
                  
                  
                  
                  244,031Long-term
      debt - revolving term credit facilities
                  
                  
                  126,171
                  
                  
                  
                  378,514
                  
                  
                  
                  504,685Long-term
      debt - convertible debentures
                  
                  
                  59,031
                  
                  
                  
                  177,092
                  
                  
                  
                  236,123Financial
      derivative instruments (asset) liability
                  
                  $
                  (15,806
                  )
                  
                  $
                  70,476
                  
                  
                  $
                  54,670
 
 Provident
Energy 2008 Financial Statements and Notes
 - 31
-
 
 Year
      ended December 31, 2007Provident
                  
                  
                  ProvidentUpstream
                  
                  
                  Midstream
      (1)
                  
                  
                  TotalRevenueGross
      production revenue
                  
                  $
                  454,179
                  
                  
                  $
                  -
                  
                  
                  $
                  454,179Royalties
                  
                  
                  (87,046
                  )
                  
                  
                  -
                  
                  
                  
                  (87,046
                  )Product
      sales and service revenue
                  
                  
                  -
                  
                  
                  
                  1,958,372
                  
                  
                  
                  1,958,372Realized gain
      (loss) on financial derivative instruments
                  
                  
                  1,728
                  
                  
                  
                  (74,474
                  )
                  
                  
                  (72,746
                  )368,861
                  
                  
                  
                  1,883,898
                  
                  
                  
                  2,252,759ExpensesCost of
      goods sold
                  
                  
                  -
                  
                  
                  
                  1,594,639
                  
                  
                  
                  1,594,639Production,
      operating and maintenance
                  
                  
                  112,387
                  
                  
                  
                  14,094
                  
                  
                  
                  126,481Transportation
                  
                  
                  8,193
                  
                  
                  
                  16,825
                  
                  
                  
                  25,018Foreign
      exchange (gain) loss and other
                  
                  
                  (573
                  )
                  
                  
                  3,996
                  
                  
                  
                  3,423General
      and administrative
                  
                  
                  27,102
                  
                  
                  
                  28,669
                  
                  
                  
                  55,771147,109
                  
                  
                  
                  1,658,223
                  
                  
                  
                  1,805,332Earnings
      before interest, taxes, depletion, depreciation,accretion
      and other non-cash items
                  
                  
                  221,752
                  
                  
                  
                  225,675
                  
                  
                  
                  447,427Other
      revenueUnrealized
      gain (loss) on financial derivative instruments
                  
                  
                  (21,324
                  )
                  
                  
                  (192,920
                  )
                  
                  
                  (214,244
                  )Other
      expensesDepletion,
      depreciation and accretion
                  
                  
                  256,723
                  
                  
                  
                  44,388
                  
                  
                  
                  301,111Goodwill
      impairment
                  
                  
                  -
                  
                  
                  
                  -
                  
                  
                  
                  -Interest on
      bank debt
                  
                  
                  11,055
                  
                  
                  
                  33,166
                  
                  
                  
                  44,221Interest and
      accretion on convertible debentures
                  
                  
                  3,672
                  
                  
                  
                  11,015
                  
                  
                  
                  14,687Unrealized
      foreign exchange (gain) loss and other
                  
                  
                  779
                  
                  
                  
                  -
                  
                  
                  
                  779Non-cash unit
      based compensation
                  
                  
                  3,698
                  
                  
                  
                  4,366
                  
                  
                  
                  8,064Internal
      management charge
                  
                  
                  (1,482
                  )
                  
                  
                  -
                  
                  
                  
                  (1,482
                  )Capital
      tax expense
                  
                  
                  3,762
                  
                  
                  
                  -
                  
                  
                  
                  3,762Current
      and withholding tax (recovery) expense
                  
                  
                  (254
                  )
                  
                  
                  6,606
                  
                  
                  
                  6,352Future
      income tax (recovery) expense (2)
                  
                  
                  (122,590
                  )
                  
                  
                  94,234
                  
                  
                  
                  (28,356
                  )155,363
                  
                  
                  
                  193,775
                  
                  
                  
                  349,138Net
      income (loss) for the year from continuing operations
                  
                  $
                  45,065
                  
                  
                  $
                  (161,020
                  )
                  
                  $
                  (115,955
                  )Net
      income from discontinued operations (note 15)
                  
                  
                  
                  
                  
                  
                  
                  
                  
                  
                  146,389Net
      income for the year
                  
                  
                  
                  
                  
                  
                  
                  
                  
                  $
                  30,434
 (1)
                  Included
      in the Provident Midstream segment is product sales and service revenue of
      $297.8 million associated with U.S.
operations.
 (2)
                  Future
      income tax (recovery) expense includes a charge of $88.4 million relating
      to the enactment of Bill C-52,
                    Budget
      Implementation Act 2007 by the Canadian
  government.
 
 Provident
Energy 2008 Financial Statements and Notes
 - 32
-
 
 As
      at and for the year ended December 31, 2007Provident
                  
                  
                  ProvidentUpstream
                  
                  
                  Midstream
                  
                  
                  TotalSelected
      balance sheet itemsCapital
      assetsProperty,
      plant and equipment net
                  
                  $
                  1,773,209
                  
                  
                  $
                  737,062
                  
                  
                  $
                  2,510,271Intangible
      assets
                  
                  
                  -
                  
                  
                  
                  171,793
                  
                  
                  
                  171,793Goodwill
                  
                  
                  416,890
                  
                  
                  
                  100,409
                  
                  
                  
                  517,299Capital
      expendituresCapital
      Expenditures
                  
                  
                  146,209
                  
                  
                  
                  31,904
                  
                  
                  
                  178,113Corporate
      acquisitions
                  
                  
                  469,795
                  
                  
                  
                  -
                  
                  
                  
                  469,795Oil
      and gas property acquisitions, net
                  
                  
                  13,050
                  
                  
                  
                  -
                  
                  
                  
                  13,050Goodwill
      additions (impairments)
                  
                  
                  85,946
                  
                  
                  
                  -
                  
                  
                  
                  85,946Working
      capitalAccounts
      receivable
                  
                  
                  75,292
                  
                  
                  
                  262,813
                  
                  
                  
                  338,105Petroleum
      product inventory
                  
                  
                  -
                  
                  
                  
                  84,638
                  
                  
                  
                  84,638Accounts
      payable and accrued liabilities
                  
                  
                  132,650
                  
                  
                  
                  214,574
                  
                  
                  
                  347,224Long-term
      debt - revolving term credit facilities
                  
                  
                  230,999
                  
                  
                  
                  692,997
                  
                  
                  
                  923,996Long-term
      debt - convertible debentures
                  
                  
                  64,110
                  
                  
                  
                  192,330
                  
                  
                  
                  256,440Financial
      derivative instruments (asset) liability
                  
                  $
                  13,559
                  
                  
                  $
                  261,587
                  
                  
                  $
                  275,146
 
 Provident
Energy 2008 Financial Statements and Notes
 - 33
-
 
 18.
                Reconciliation
      of financial statements to United States
                  generally
      accepted accounting principles (U.S.
GAAP)
  The
consolidated financial statements have been prepared in accordance with
accounting principles generally accepted in Canada (“Canadian
GAAP”).  Any differences in accounting principles to U.S. GAAP as they
pertain to the accompanying financial statements are not material except as
described below.  All adjustments are measurement
differences.  Disclosure items are not noted.
  Consolidated
      Statements of Earnings - U.S. GAAPFor
      the year ended December 31, (Cdn $000s)
                  
                  2008
                  
                  
                  2007Net
      income as reported
                  
                  $
                  157,392
                  
                  
                  $
                  30,434AdjustmentsDepletion,
      depreciation and accretion (a)
                  
                  
                  79,558
                  
                  
                  
                  65,306Depletion,
      depreciation and accretion other (a)
                  
                  
                  (813,983
                  )
                  
                  
                  (181,551
                  )Goodwill
      impairment (g)
                  
                  
                  416,890
                  
                  
                  
                  -General
      and administrative (d)
                  
                  
                  -
                  
                  
                  
                  483Future
      income tax recovery (a) (b)
                  
                  
                  180,161
                  
                  
                  
                  25,371Accretion
      on convertible debentures (e)
                  
                  
                  3,010
                  
                  
                  
                  2,802Gain
      on sale of discontinued operations
                  
                  
                  (8,983
                  )
                  
                  
                  -Other
      adjustments to net income from discontinued operations
                  
                  
                  2,976
                  
                  
                  
                  2,538Net
      income (loss) – U.S. GAAP
                  
                  $
                  17,021
                  
                  
                  $
                  (54,617
                  )Other
      comprehensive income (loss)
                  
                  
                  67,005
                  
                  
                  
                  (26,000
                  )Comprehensive
      income (loss)
                  
                  
                  84,026
                  
                  
                  
                  (80,617
                  )Net
      loss from continuing operations per unit - basic and
    diluted
                  
                  $
                  (0.48
                  )
                  
                  $
                  (0.89
                  )Net
      income (loss) per unit - basic and diluted
                  
                  $
                  0.07
                  
                  
                  $
                  (0.24
                  )
  Condensed
      Consolidated Balance SheetAs
      at December 31, (Cdn$ 000s)
                  
                  2008
                  
                  
                  2007Canadian
                    GAAP
                  
                  
                  U.S.
      GAAP
                  
                  
                  Canadian
                    GAAP
                  
                  
                  U.S.
      GAAPAssetsDeferred
      financing charges (e)
                  
                  $
                  -
                  
                  
                  $
                  4,921
                  
                  
                  $
                  -
                  
                  
                  $
                  8,266Property,
      plant and equipment (a)
                  
                  
                  2,480,503
                  
                  
                  
                  1,198,561
                  
                  
                  
                  2,510,271
                  
                  
                  
                  1,962,754Goodwill
      (g)
                  
                  
                  100,409
                  
                  
                  
                  517,299
                  
                  
                  
                  517,299
                  
                  
                  
                  517,299Long-term
      assets held for sale - USOGP
                  
                  
                  -
                  
                  
                  
                  -
                  
                  
                  
                  2,027,604
                  
                  
                  
                  2,046,025Liabilities
      and unitholders’ equityCurrent
      portion of convertible debentures (e)
                  
                  
                  24,871
                  
                  
                  
                  25,109
                  
                  
                  
                  19,198
                  
                  
                  
                  19,931Long-term
      debt - revolving term credit facilities (e)
                  
                  
                  504,685
                  
                  
                  
                  504,912
                  
                  
                  
                  923,996
                  
                  
                  
                  925,266Long-term
      debt - convertible debentures (e)
                  
                  
                  236,123
                  
                  
                  
                  248,979
                  
                  
                  
                  256,440
                  
                  
                  
                  274,113Future
      income tax liability (asset) (a) (b)
                  
                  
                  267,807
                  
                  
                  
                  (68,733
                  )
                  
                  
                  302,089
                  
                  
                  
                  145,710Long-term
      liabilities held for sale - USOGP
                  
                  
                  -
                  
                  
                  
                  -
                  
                  
                  
                  628,502
                  
                  
                  
                  638,021Non-controlling
      interests
                  
                  
                  -
                  
                  
                  
                  -
                  
                  
                  
                  1,100,136
                  
                  
                  
                  1,103,031Units
      subject to redemption (f)
                  
                  
                  -
                  
                  
                  
                  1,381,352
                  
                  
                  
                  -
                  
                  
                  
                  2,308,273Unitholders'
      equity (e) (f)
                  
                  
                  1,638,530
                  
                  
                  
                  (279,734
                  )
                  
                  
                  1,777,853
                  
                  
                  
                  (926,961
                  )
   (a)
                Under
      the Canadian cost recovery ceiling test the recoverability of a cost
      centre is tested by comparing the
                  carrying
      value of the cost centre to the sum of the undiscounted proved reserve
      cash flows expected from
                  the
      cost centre using future price estimates.  If the carrying value
      is not recoverable, the cost centre is
                  written
      down to its fair value determined by comparing the future cash flows from
      the proved plus probable
                  reserves
      discounted at the Trust’s risk free interest rate.   Any
      excess carrying value of the assets on the
                  balance
      sheet above fair value would be recorded in depletion, depreciation and
      accretion expense as a
                  permanent
      impairment.  Under U.S. GAAP, companies utilizing the full cost
      method of accounting for oil
                  and
      natural gas activities perform a ceiling test on each cost centre using
      discounted future net revenue
 
 Provident
Energy 2008 Financial Statements and Notes
 - 34
-
 
 from
      proved oil and natural gas reserves discounted at 10
      percent.  Prices used in the U.S. GAAP ceiling
                  tests
      are those in effect at year-end.  The amounts recorded for
      depletion and depreciation have been
                  adjusted
      in the periods as a result of differences in write down amounts recorded
      pursuant to U.S. GAAP
                  compared
      to Canadian GAAP.
 
 In
computing its consolidated net earnings for U.S. GAAP purposes, the Trust
recorded additional depletion in 2008 of $814.0million (2007 – $181.6
million) and a related future income tax recovery of $214.3million (2007 - $52.2
million) as a result of the application of the ceiling test.  These
charges were not required under the Canadian GAAP ceiling tests.
 
 (b)
                The
      Canadian liability method of accounting for income taxes in CICA handbook
      Section 3465 “Income taxes” is similar to the United States FAS 109,
      “Accounting for Income Taxes”, which requires the recognition of deferred
      tax assets and liabilities for the expected future tax consequences of
      events that have been recognized in Provident’s financial statements or
      tax returns.  Pursuant to U.S. GAAP, enacted tax rates are used
      to calculate future taxes, whereas Canadian GAAP uses substantively
      enacted rates.
 
 In July
2006, the FASB issued FIN 48, “Accounting for Uncertainty in Income
Taxes”.  The interpretation creates a single model to address
uncertainty in tax positions and clarifies the accounting for income taxes by
prescribing the minimum recognition threshold a tax position is required to meet
before being recognized in the financial statements.  The statement
also provides guidance on de-recognition, measurement, classification, interest
and penalties, accounting in interim periods, disclosures and transitions as
well as specifically scopes out accounting for contingencies.  FIN 48
is effective for fiscal years beginning after December 15, 2006.  The
adoption of this statement has not resulted in a Canadian to U.S. GAAP
difference.
 
 (c)
                The
      consolidated statements of cash flows and operations and accumulated
      income are prepared in accordance with Canadian GAAP and conform in all
      material respects with U.S. GAAP except for the
  following;
 (i)
      Canadian GAAP allows for the presentation of funds flow from operations in
      the consolidated statement of cash flows.  This total cannot be
      presented under U.S. GAAP.
 (ii)
      U.S. GAAP requires disclosure on the consolidated statement of operations
      when depreciation, depletion and amortization are excluded from cost of
      goods sold.  This disclosure has not been noted on the face of
      the consolidated statement of
operations.
 
 (d)
                Under
      Canadian GAAP, Provident follows CICA handbook Section 3870 “Stock-based
      compensation and other stock-based payments” which provides for the
      presentation and measurement of cash-settled unit-based compensation as
      liabilities based on the intrinsic value each period.  Under
      U.S. GAAP FAS 123R “Share-based payments”, public entities are required to
      measure liability awards based on the award’s fair value re-measured at
      each reporting date until the date of
      settlement.    Compensation cost for each period is
      based on the change in the fair value of the units for each reporting
      period and is recognized over the vesting
  period.
 
 (e)
                Under
      Canadian GAAP Provident applies EIC Abstract 164 “Convertible and other
      instruments with embedded derivatives” to account for the convertible
      debentures.  Under U.S. GAAP, the convertible debentures are
      disclosed as long-term debt at their face value versus Canadian GAAP that
      requires discounting of the convertible debentures, accretion expense to
      represent the unwinding of the discounted convertible debentures and a
      value assigned within equity to the conversion feature component of the
      convertible debentures.  In addition, U.S. GAAP requires debt
      issue costs to be reported as deferred charges on the consolidated balance
      sheet.  In December 2008, the Trust repaid $19.9 million to the
      holders of its 8.75 percent convertible debentures.  Upon
      maturity, the Trust transferred $1.0 million of the equity component to
      contributed surplus under Canadian GAAP.  Under U.S. GAAP, this
      amount would not have been transferred as convertible debentures are
      recorded in long-term debt at face
value.
 
 (f)
                Under
      U.S. GAAP, a redemption feature of equity instruments exercisable at the
      option of the holder requires that such equity be excluded from
      classification as permanent equity and be reported as temporary equity at
      the equity’s redemption value.  Decreases in redemption value in
      the period (2008 - $982.6
 
 Provident
Energy 2008 Financial Statements and Notes
 - 35
-
 
 million;
      2007 - $505.1 million) are recorded to accumulated
      earnings.  Under Canadian GAAP, such equity instruments are
      considered to be permanent equity and are presented as unitholder’s
      equity.  The Trust’s units have a redemption feature, which
      qualify them to be considered under this
  guidance.
 
 (g)
                Under
      both Canadian and U.S. GAAP, goodwill is tested for impairment at least
      annually.  Both GAAP’s require that the fair value of the
      reporting unit be determined and compared to the book value of the
      reporting unit.  Under Canadian GAAP, this resulted in a $416.9
      million impairment being recorded.  Under U.S. GAAP the book
      value of the reporting unit was lower than the Canadian GAAP book value,
      primarily due to ceiling test impairments.  Using the lower book
      value under U.S. GAAP results in no goodwill
  impairment.
 
 
 Recent
U.S. Accounting Pronouncements
 
 Non-controlling
interests in consolidated financial statements
  In
December 2007, the FASB issued FAS 160 “Non-controlling interests in
Consolidated Financial Statements.” FAS 160 requires the ownership interests in
subsidiaries held by parties other than the parent be clearly presented in the
consolidated balance sheet within equity, but separate from the parent’s equity
and the amount of consolidated net income attributable to the parent and the
non-controlling interest be clearly identified and presented on the face of the
consolidated statement of operations. Changes in the parent’s ownership interest
should be accounted for consistently as equity transactions. If a subsidiary is
deconsolidated, any retained non-controlling equity investment in the former
subsidiary should be initially recorded at fair value and the gain or loss on
the deconsolidation of the subsidiary is measured using the fair value of any
non-controlling equity investment rather than the carrying amount of the
retained investment. This statement is effective for fiscal years, and interim
periods, beginning on or after December 15, 2008.  The Trust does not
expect the adoption of this statement to have a material impact on its financial
statements.
 
 Business
combinations
  In
December 2007, the FASB revised FAS 141 “Business Combinations.” FAS 141
establishes how an acquirer recognizes and measures in its financial statements
the identifiable assets and liabilities as well as any non-controlling interest
in the acquiree, how an acquirer should recognize and measure goodwill acquired
in the business combination or a gain from a bargain purchase, and how an
acquirer determines what information to disclose to enable users of the
financial statements to evaluate the nature and financial effects of the
business combination. The statement specifically addresses the treatment of
acquisition costs separate from the acquisition as opposed to including them as
part of the acquisition purchase price.  This statement applies
prospectively to business combinations for which the acquisition date is on or
after the beginning of the first annual reporting period beginning on or after
December 15, 2008. The adoption of this statement will impact any future
business combination with an acquisition date after January 1,
2009.
 
 The
fair value option for financial assets and financial liabilities
  In
February 2007, the FASB issued FAS 159 “The Fair Value Option for Financial
Assets and Financial Liabilities.” FAS 159 permits entities to chose to measure
eligible items at fair value at specified election dates. The entity would
record gains and losses on items for which the fair value option has been
elected in earnings at each subsequent reporting date. This statement is
effective as of the beginning of an entity’s first fiscal year that begins after
November 15, 2007. The adoption of this statement has not had a material impact
on the Trust’s financial statements.
 
 Fair
value measurement
  In
September 2006, the FASB issued FAS 157 “Fair value measurement.” FAS 157
defines fair value, establishes a framework for measuring fair value in
generally accepted accounting principles and expands disclosures about fair
value measurements. This statement does not require any new fair value
measurements. Fair value is defined in this statement as the exchange price,
which is the price in an orderly transaction between market participants to sell
the asset or transfer the liability in the market in which the reporting entity
would transact for the asset or liability, that is, the principal or most
advantageous market for the asset or liability. The statement is effective for
financial statements issued for fiscal years beginning after November 15, 2007,
and interim periods of those fiscal years. The adoption of this statement has
not had a material impact on the Trust’s financial statements.
 
 Provident
Energy 2008 Financial Statements and Notes
 - 36
-
 Oil
and gas reporting disclosure
  During
2008, the United States Securities and Exchange Commission adopted revisions to
its oil and gas reporting disclosures contained in Regulation S-K and Regulation
S-X.  These revisions change the price basis for calculating reserves
from a single-day, year-end price to a monthly average price based on the first
day of each month.  These revisions impact the reserves in the Trust’s
accounting for depletion and its calculation of the ceiling test under US
GAAP.  These revisions are effective for filings made on or after
January 1, 2010 and will be applied prospectively with no retroactive
restatement.
  
 Provident
Energy 2008 Financial Statements and Notes
 - 37
-
  ADDITIONAL
DISCLOSURE




Certifications
and Disclosure Regarding Controls and Procedures.




(a)
            Certifications.  See
      Exhibits 99.1 and 99.2 to this Annual Report on Form
  40-F.




(b)
            Disclosure Controls
      and Procedures.  As of the end of the registrant’s fiscal
      year ended December 31, 2008, an evaluation of the effectiveness of the
      registrant’s “disclosure controls and procedures” (as such term is defined
      in Rules 13a-15(e) and 15d-15(e) of the Securities Exchange Act of 1934,
      as amended (the “Exchange Act”)) was carried out by the management of
      Provident Energy Ltd., the administrator of the registrant, with the
      participation of the Chief Executive Officer (“CEO”) and Chief Financial
      Officer (“CFO”) of Provident Energy Ltd., who also perform such functions
      for the registrant.  Based upon that evaluation, the CEO and CFO
      have concluded that as of the end of that fiscal year, the registrant’s
      disclosure controls and procedures are effective to ensure that
      information required to be disclosed by the registrant in reports that it
      files or submits under the Exchange Act is (i) recorded, processed,
      summarized and reported within the time periods specified in Securities
      and Exchange Commission rules and forms and (ii) accumulated and
      communicated to the registrant’s management, including its principal
      executive officer and principal financial officer, to allow timely
      decisions regarding required
disclosure.





It should
be noted that while the CEO and CFO believe that the registrant’s disclosure
controls and procedures provide a reasonable level of assurance that they are
effective, they do not expect that the registrant’s disclosure controls and
procedures or internal control over financial reporting will prevent all errors
and fraud.  A control system, no matter how well conceived or
operated, can provide only reasonable, not absolute, assurance that the
objectives of the control system are met.





(c)
            Management’s Annual
      Report on Internal Control Over Financial Reporting.  The
      required disclosure is included in the “Management Report” that
      accompanies the registrant’s Consolidated Financial Statements for the
      fiscal year ended December 31, 2008, filed as part of this Annual Report
      on Form 40-F.





(d)
            Attestation Report of
      the Registered Public Accounting Firm.  The required
      disclosure is included in the “Independent Auditors’ Report” that
      accompanies the registrant’s Consolidated Financial Statements for the
      fiscal year ended December 31, 2008, filed as part of this Annual Report
      on Form 40-F.





(e)
            Changes in Internal
      Control Over Financial Reporting.  During the fiscal year
      ended December 31, 2008, there were no changes in the registrant’s
      internal control over financial reporting that have materially affected,
      or are reasonably likely to materially affect, the registrant’s internal
      control over financial reporting.





40F -
2


Notices Pursuant to Regulation
BTR.





None.





Audit
Committee Financial Expert.





The
registrant’s board of directors has determined that Mike H. Shaikh, a member of
the registrant’s audit committee, qualifies as an “audit committee financial
expert” (as such term is defined in Form 40-F).  Mr. Shaikh satisfies
the specified criteria for being “independent” under the rules of the New York
Stock Exchange, but the registrant’s board of directors has not affirmatively
made any such independence determination.





Code of Ethics.





The
registrant has adopted a “code of ethics” (as that term is defined in Form 40-F)
that applies to its principal executive officer, principal financial officer,
principal accounting officer or controller, and persons performing similar
functions.




The Code
of Ethics is available for viewing on the registrant’s website at
www.providentenergy.com.




In
connection with the registrant’s listing on the New York Stock Exchange, the
Code of Ethics was amended in March 2006 to reflect the New York Stock
Exchange’s guidelines for codes of ethics.  Since the adoption of the
Code of Ethics, other than such amendment, there have not been any amendments to
the Code of Ethics or waivers, including implicit waivers, from any provision of
the Code of Ethics.




Principal
Accountant Fees and Services.




The
required disclosure is included under the heading Audit Committee Information—External
Auditor Service Feesin the registrant’s Renewal Annual Information Form
for the fiscal year ended December 31, 2008, filed as part of this Annual Report
on Form 40-F.




Pre-Approval
Policies and Procedures.




(a)
            The
      required disclosure is included under the heading “Audit Committee
      Information—External Auditor Service Fees”in the
      registrant’s Renewal Annual Information Form for the fiscal year ended
      December 31, 2008, filed as part of this Annual Report on Form
      40-F.




(b)
            Of
      the fees reported under the heading “Audit Committee
      Information—External Auditor Service Fees” in the registrant’s
      Renewal Annual Information Form for the fiscal year ended December 31,
      2008, filed as part of this Annual Report on Form 40-F, none of the fees
      billed by PricewaterhouseCoopers LLP were approved by the audit committee
      of the registrant pursuant to the de minimis exception
      provided by Section (c)(7)(i)(C) of Rule 2-01 of
      Regulation  S-X.




40F -
3




Off-Balance
Sheet Arrangements.




The
registrant does not have any off-balance sheet arrangements that have or are
reasonably likely to have a current or future effect on its results of
operations, revenues, expenses, liquidity, capital expenditures, capital
resources or financial condition.




Tabular
Disclosure of Contractual Obligations.




Consolidated
            
            
            
            
            Payment
      Due By PeriodCdn.$
      Millions
            
            Total
            
            
            Less
      than
              1
      year
            
            
            1
      – 3
              years
            
            
            3
      – 5
              years
            
            
            More
      than
              5
      yearsLong-term
      debt – revolving term credit facilities(1)(3)
            
            $
            548.8
            
            
            $
            16.8
            
            
            $
            532.0
            
            
            $
            -
            
            
            $
            -Long-term
      debt – convertible debentures(2)(3)
            
            
            321.6
            
            
            
            42.5
            
            
            
            175.8
            
            
            
            103.3
            
            
            
            -Operating
      lease obligations
            
            
            195.6
            
            
            
            22.3
            
            
            
            37.6
            
            
            
            29.1
            
            
            
            106.6Total
            
            $
            1,066.0
            
            
            $
            81.6
            
            
            $
            745.4
            
            
            $
            132.4
            
            
            $
            106.6


(1)
            The
      terms of the Canadian credit facility have a revolving three year period
      expiring on May 30, 2011.


(2)
            Includes
      current portion of convertible
debentures.


(3)
            Includes
      associated interest and principal
payments.


Identification
of the Audit Committee.




The
registrant has a separately-designated standing audit committee established in
accordance with Section 3(a)(58)(A) of the Exchange Act.  The members
of the audit committee are:  Mike H. Shaikh, Hugh A. Ferguson and
Bruce R. Libin.




Disclosure
Pursuant to the Requirements of the New York Stock Exchange.





Presiding
Director at Meetings of Non-Management Directors and Director
Independence





The
registrant schedules regular executive sessions in which the registrant's
"non-management directors"(as that term is defined in the rules of the New York
Stock Exchange) meet without management participation.  Mr. John
Zaozirny serves as the presiding director (the "Presiding Director") at such
sessions.  Each of the registrant's non-management directors is
"unrelated" as such term is used in the rules of the Toronto Stock Exchange. The
Provident Board of Directors is responsible for determining whether or not each
director is independent.  In making this determination, the Board has
adopted the definition of "independence" as set out in Section 1.4 of
Multilateral Instrument 52-110 Audit Committees ("MI-51-110").  In
applying this definition, the Board considers all relationships of the directors
with Provident, including business, family and other
relationships.  Provident's Board of Directors also determines whether
each member of Provident's Audit Committee is independent pursuant to Sections
1.4 and 1.5 of MI 52-110 and Rule 10A-3 of the Exchange
Act.  Provident's Board of Directors has not adopted the director
independence standards contained in Section 303A.02 of the NYSE's Listed Company
Manual.





40F -
4


Communication
with Non-Management Directors





Shareholders
may send communications to the registrant's non-management directors by writing
to the Presiding Director, c/o Lynn M. Rannelli, Assistant Corporate Secretary,
Provident Energy Ltd., 2100, 250 2nd Street
S.W., Calgary, Alberta, Canada  T2P 0H3.  Communications
will be referred to the Presiding Director for appropriate
action.  The status of all outstanding concerns addressed to the
Presiding Director will be reported to the board of directors as
appropriate.





Corporate
Governance Guidelines





According
to Section 303A.09 of the NYSE Listed Company Manual, a listed company must
adopt and disclose a set of corporate governance guidelines with respect to
specified topics.  Such guidelines are required to be posted on the
listed company's website.  The registrant operates under corporate
governance principles that are consistent with the requirements of Section
303A.09 of the NYSE Listed Company Manual, many of which are described under the
heading "Statement of Corporate Governance Practices" in the registrant's
Information Circular in connection with its 2008 Annual
Meeting.  However, the registrant has not codified its corporate
governance principles into formal guidelines in order to post them on its
website.





Board
Committee Mandates





The
Mandates of the registrant's audit committee, human resources and compensation
committee, and nominating and corporate governance committee, are each available
for viewing on the registrant's website at www.providentenergy.com, and are
available in print to any unitholder who requests them.  Requests for
copies of these documents should be made by contacting: Lynn M. Rannelli,
Assistant Corporate Secretary, Provident Energy Ltd., 2100, 250 – 2nd Street
S.W., Calgary, Alberta, Canada T2P 0H3.


Alternatively,
requests for these documents may be made by contacting the registrant's
Corporate Secretarial Department at (403) 296-2233 (Fax: (403)
205-3539).




40F -
5


UNDERTAKING
AND CONSENT TO SERVICE OF PROCESS




A.
              Undertaking.


The
registrant undertakes to make available, in person or by telephone,
representatives to respond to inquiries made by the Securities and Exchange
Commission (the “Commission”) staff, and to furnish promptly, when requested to
do so by the Commission staff, information relating to:  the
securities registered pursuant to Form   40-F; the securities in
relation to which the obligation to file an annual report on Form 40-F arises;
or transactions in said securities.




B.
            Consent
      to Service of Process.




The
Company has previously filed a Form F-X in connection with the class of
securities in relation to which the obligation to file this report
arises.




Any
change to the name or address of the agent for service of process of the
registrant shall be communicated promptly to the Securities and Exchange
Commission by an amendment to the Form F-X referencing the file number of the
registrant.




SIGNATURES




Pursuant
to the requirements of the Exchange Act, the registrant certifies that it meets
all of the requirements for filing on Form 40-F and has duly caused this annual
report to be signed on its behalf by the undersigned, thereunto duly authorized,
on March 19,
2009.










PROVIDENT ENERGY
      TRUSTBy:  Provident Energy
      Ltd., its administrator




By:   __/s/Thomas W.
      Buchanan_________


Name:  Thomas
      W. BuchananTitle:    President
      and Chief Executive Officer




40F -
6


EXHIBIT
INDEX





Exhibit
            Description99.1
            Certification
      of Chief Executive Officer pursuant to Rule 13a-14(a) or 15d-14 of the
      Securities Exchange Act of 193499.2
            Certification
      of Chief Financial Officer pursuant to Rule 13a-14(a) or 15d-14 of the
      Securities Exchange Act of 193499.3
            Certification
      of Chief Executive Officer pursuant to 18 U.S.C. Section
    135099.4
            Certification
      of Chief Financial Officer pursuant to 18 U.S.C. Section
    135099.5
            Consent
      of PricewaterhouseCoopers LLP99.6
            Consent
      of McDaniel & Associates Consultants Ltd.99.7
            Consent
      of AJM Petroleum Consultants