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, 2007




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
              Trust
      Units
            Name of each exchange
      on which registered
              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, 2007:  252,108,951




Indicate
by check mark whether the registrant by filing the information contained in this
Form is also thereby furnishing the information to the Commission pursuant to
Rule 12g3-2(b) under the Securities Exchange Act of 1934 (the “Exchange
Act”).  If “Yes” is marked, indicate the file number assigned to the
registrant in connection with such rule.




Yes
___                                NoX




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,
    2007;
  (b)
              Management’s
      Discussion and Analysis of Financial Condition; and Results of Operations
      for the fiscal year ended December 31, 2007; and(c)
              Consolidated
      Financial Statements for the fiscal year ended December 31, 2007 (Note 19 to the Consolidated
      Financial Statements relates to United States Accounting Principles and
      Reporting (U.S. GAAP).





RENEWAL
ANNUAL INFORMATION FORM
  For the
year ended December 31, 2007
  
 
  
  
  March 27,
2008
    
 TABLE OF
CONTENTS
 Page
                
                PageGLOSSARY
      OF TERMS
                1
                RISK
      MANAGEMENT
                27ABBREVIATIONS,
      TERMS AND
                  CONVERSIONS
                4
                General
                27PRESENTATION
      OF OIL AND GAS
                  RESERVES
      AND PRODUCTION
                  INFORMATION
                5
                Risk
      Management
                28NON-GAAP
      MEASURES
                5
                OIL
      AND NATURAL GAS OPERATIONS
                30NOTE
      REGARDING FORWARD
                  LOOKING
      STATEMENTS
                6
                NATURAL
      GAS MIDSTREAM, NGL
                  PROCESSING
      AND MARKETING
                  OPERATIONS
                30INCORPORATION
      AND STRUCTURE
                8
                GeneralThe
      Trust
                8
                NGL
      Extraction
                31Provident
                8
                NGL
      Fractionation
                31Provident
      Holdings Trust
                9
                NGL
      Transportation
                31Provident
      Acquisitions L.P
                9
                NGL
      Storage
                32Provident
      Midstream L.P
                9
                NGL
      Marketing
                32Provident
      Acquisitions Inc
                9
                Commercial
      Arrangements
                32Provident
      Midstream Inc
                9
                Midstream
      services and marketing assets
                33Provident
      Energy Resources Inc
                10
                MARKET
      FOR SECURITIES
                35Pro
      Holding Company
                10
                RECORD
      OF CASH DISTRIBUTIONS
                37BreitBurn
      Energy Company L.P
                10
                PREMIUM
      DISTRIBUTION, DISTRIBUTION
                  REINVESTMENT
      AND OPTIONAL UNIT
                  PURCHASE
      PLAN
                38BreitBurn
      Energy Partners L.P
                10
                DIRECTORS
      AND OFFICERS
                39INTERCORPORATE
      RELATIONSHIPS
                10
                AUDIT
      COMMITTEE INFORMATION
                44INFORMATION
      CONCERNING THE
                  TRUST,
      PROVIDENT AND CERTAIN
                  SUBSIDIARIES
                11
                INFORMATION
      CONCERNING THE
                  OIL
      AND GAS INDUSTRY
                47Provident
      Energy Trust
                11
                RISK
      FACTORS
                50Provident
      Energy Ltd
                20
                Oil and
      Gas Production Risk Factors
                50Provident
      Holdings Trust, Provident
                  Acquisitions
      L.P., Provident
                  Marketing L.P.
      and Provident
                  Midstream
      L.P
                21
                Natural
      Gas Midstream, NGL
                  Processing and
      Marketing Business
                  Risk
      Factors
                54Provident
      Energy Resources Inc
                22
                General
      Risk Factors
                57Provident
      Acquisitions Inc
                22
                INTERESTS
      OF MANAGEMENT AND
                  OTHERS
      IN MATERIAL TRANSACTIONS
                60Provident
      Midstream Inc
                22
                TRANSFER
      AGENT AND REGISTRAR
                60Pro
      Holding Company
                22
                INTERESTS
      OF EXPERTS
                60BreitBurn
      Energy Company L.P
                22
                MATERIAL
      CONTRACTS
                60BreitBurn
      Energy Partners L.P
                23
                DOCUMENTS
      INCORPORATED BY
                  REFERENCE
                60GENERAL
      DEVELOPMENT OF THE
                  BUSINESS
      OF THE TRUST AND
                  PROVIDENT
                23
                PRINCIPAL
      HOLDERS OF TRUST UNITS
                61ADDITIONAL
      INFORMATION
                61
  SCHEDULE
      A -
                AUDIT
      COMMITTEE INFORMATION
   
 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
(Alberta), S.A. 1981, c. B-15, 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 an indirect subsidiary
of the Trust;
  "Board of Directors" or "Board" means the board of
directors of Provident;
  "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 Provident;
  "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 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;
  "NSAI" means Netherland, Sewell
and Associates, Inc., independent petroleum engineers;
  "Nautilus" means Nautilus
Resources LLC;
  "Nautilus Acquisition" means
the acquisition of all of the membership interests in Nautilus by BEC L.P.
pursuant to a membership interest purchase and sale agreement dated February 9,
2005 among BEC L.P. and all of the membership interest holders of
Nautilus;
  "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;
  "Orcutt Hill Acquisition" means
the acquisition by BEC L.P. of certain oil and natural gas producing properties,
related interests and 5,000 acres of surface acreage situated in the Orcutt Hill
Oil Field located in Santa Barbara County, California pursuant to a purchase and
sale agreement dated September 13, 2004 between BEC L.P. and an arm's
length third party vendor;
  "Orcutt Hill Properties" means
the oil and natural gas producing properties, related interests and 5,000 acres
of surface acreage situated in the Orcutt Hill Oil Field located in Santa
Barbara County, California acquired by BEC L.P. pursuant to the Orcutt Hill
Acquisition;
  "PAI" means Provident
Acquisitions Inc.;
  "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;
  "PMI" means Provident Midstream
Inc.;
  "PHC" means Pro Holding
Company;
  "Provident" means Provident
Energy Ltd.;
  
 "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.;
  "Schlumberger" means Data &
Consulting Services Division of Schlumberger Technology
Corporation;
  "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 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;
  "Special Voting Unit" means a
special voting unit of the Trust, which shall be entitled to such number of
votes at meetings of Unitholders equal to such number of votes and any other
rights or limitations to be prescribed by the board of directors of Provident in
the resolution issuing any such Special Voting Units;
  "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 Provident 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 bodiescorporate
      each of which is controlled by that other,
or
  (b)           a
subsidiary of a body corporate that is the other's subsidiary;
  and in
the case of the Trust, includes Provident;
  "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 (Canada),
R.S.C. 1985, c.1, 5th Supplement, 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
 
   "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
  "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 oil
  Otherboe
                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
                
                0.950
  PRESENTATION
OF OIL AND GAS RESERVES AND PRODUCTION INFORMATION
  All oil
and natural gas reserve information contained 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 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.  The Trust has adopted 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", "adjusted
cash flow" and "funds flow from operations" to refer to the amount of cash
available for distribution to Unitholders and as indicators of financial
performance.  "Cash flow", "adjusted 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", "adjusted 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",
"adjusted 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", "adjusted 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 STATEMENTS
  This
Renewal Annual Information Form and the documents incorporated by reference
herein contain forward-looking information or forward-looking statements under
applicable securities legislation.  These statements relate to future
events or the Trust's future performance.  Such forward-looking
statements or information are 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 statements.  In some cases, forward-looking
statements 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 statements, as they involve the implied assessment,
based on certain estimates and assumptions, that the resources and reserves
described can be profitably produced in the future.  Forward looking
statements or information in this Renewal Annual Information Form include, but
are 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 statements or
information are 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 statements or information.  In addition, this
Renewal Annual Information Form and the documents incorporated by reference
herein may contain forward-looking statements attributed to third party industry
sources.  Undue reliance should not be placed on forward-looking
statements or 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 statements will not occur.  Forward-looking statements
in this Renewal Annual Information Form and the documents incorporated by
reference herein include, but are 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;
 ·
                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 a consistent 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
                  hedging;
 ·
                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
statements 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
statements.  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 or forward-looking statements
contained in this Renewal Annual Information Form and the documents incorporated
by reference herein include, but are not limited to:
  ·
                general
      economic 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 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
      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 "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 forwarding looking statements and
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 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;
  - 7
-
 ·
                the
      impact of increasing competition;
and
 ·
                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.  The forward-looking statements or
information contained or incorporated by reference in this Renewal Annual
Information Form are made as of the date hereof and the Trust undertakes no
obligation to update publicly or revise any forward-looking statements or
information, whether as a result of new information, future events or otherwise
unless required by applicable securities laws. The forward looking statements or
information contained or incorporated by reference in this Renewal Annual
Information Form are 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
  Provident
Energy Ltd. is a corporation the common shares of which are wholly-owned by the
Trust.  Provident was incorporated under the ABCA on January 19, 2001
and was amalgamated with Founders pursuant to a plan of arrangement involving
the Trust, Provident and Founders effective March 6, 2001.  Provident
subsequently amalgamated with Maxx Petroleum Ltd. ("Maxx") effective May 25,
2001 pursuant to a plan of arrangement involving the Trust, Provident and
Maxx.  Provident was also amalgamated with Richland Petroleum
Corporation ("Richland") effective January 16, 2002 pursuant to a plan of
arrangement involving the Trust, Provident and Richland.  Provident
was amalgamated with Provident Management Corporation pursuant to a management
internalization transaction involving the Trust, Provident, Provident Management
Corporation and its shareholders effective January 17,
2003.  Provident was also amalgamated with Olympia Energy Inc. and
Viracocha Energy Inc. on June 1, 2004 pursuant to plans of arrangement involving
the Trust, Provident, Viracocha Energy Inc. and Olympia Energy
Inc.  The head and principal offices of Provident are located at 2100,
250 - 2nd Street
S.W., Calgary, Alberta T2P 0C1.  The registered office of Provident is
located at 3700, 400 - 3rd Avenue S.W., Calgary, Alberta T2P 4H2.
  - 8
-
 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 the limited partnerships, Provident Acquisitions L.P.
and Provident Marketing L.P. and an interest in Provident Midstream
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.  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 1 percent interest
in the partnership.  Holdings Trust and PMI are the limited partners
of Provident Midstream L.P. with a 99 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 Provident.  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
Midstream Inc.
  Provident
Midstream Inc. is a corporation wholly-owned by Provident and Pro Holding
Company.  PMI was incorporated under the ABCA on June 6,
2005.  PMI holds Provident's Redwater Midstream NGL asset and also
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
-
 Provident
Energy Resources Inc.
  Provident
Energy Resources Inc. is a corporation wholly-owned by
Provident.  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.
  Pro
Holding Company
  Pro
Holding Company is a corporation incorporated under the laws of Delaware and is
wholly-owned by the Trust and Provident.  PHC owns all of the
outstanding shares of Pro LP Corp. and Pro GP Corp. which in turn own
approximately 96 percent of the outstanding partnership interests in BEC
L.P.  PHC also owns all of the shares of Pro US LLC and Pro Midstream
Company which are the partners of the Kinetic Resources U.S.A.
partnership.  PHC also owns all of the common shares of
PMI.  The head and principal offices of PHC are located at 515 S.
Flower Street, Suite 4800, Los Angeles, California.  The registered
office of PHC is located at 2711 Centerville Road, Suite 400, Wilmington,
Delaware.
  BreitBurn
Energy Company L.P.
  BreitBurn
Energy Company L.P. is a Delaware limited partnership and an indirect subsidiary
of the Trust.  BEC L.P. resulted from the merger of BreitBurn, a
former California limited liability company, and BB Merger LLC, a Delaware
limited liability company and wholly-owned indirect subsidiary of the Trust,
upon completion of the indirect acquisition of all of the issued and outstanding
shares of BreitBurn by the Trust on June 15, 2004.  The Trust, through
Pro Holding Company, Pro LP Corp. and Pro GP Corp., currently holds
approximately96
percentof the
outstanding partnership interests in BEC L.P. with the remaining partnership
interests held by BreitBurn's co-founders and co-chief executive
officers.  The head and principal offices of BEC L.P. are located at
515 S. Flower Street, Suite 4800, Los Angeles, California.  The
registered office of BEC L.P. is 2711 Centerville Road, Suite 400, Wilmington,
Delaware.
  BreitBurn
Energy Partners L.P.
  BreitBurn
Energy Partners L.P. is a publicly traded Delaware limited partnership formed on
March 23, 2006.  BreitBurn MLP is managed by BreitBurn GP LLC,
which has a board of directors comprised of 3 directors or officers of
Provident, as well as 4 independent directors.  The Trust, through Pro
Holding Company, Pro LP Corp. and Pro GP Corp., currently holds approximately 22
percent of the outstanding partnership interests in BreitBurn
MLP.  The head and principal offices of BreitBurn MLP are located at
515 S. Flower Street, Suite 4800, Los Angeles,
California.  The registered office of BreitBurn MLP is 2711
Centerville Road, Suite 400, Wilmington, Delaware.
  INTERCORPORATE
RELATIONSHIPS
  The
following diagram of the Trust, Provident and the Trust's 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 and from the Trust
to the Unitholders.
  -10
-
  
 INFORMATION
CONCERNING THE TRUST, PROVIDENT AND CERTAIN SUBSIDIARIES
  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 Provident
and its various subsidiaries.  Cash flow from the petroleum and
natural gas properties flows from Provident and the Trust's various subsidiaries
to the Trust by way of royalty payments and interest payments and principal
repayments on notes issued by the Trust from time to time. Cash flow from the
natural gas midstream, NGL processing and marketing business flows from
Provident to the Trust and the Trust's various subsidiaries by way of interest
payments and principal repayments on notes issued by the
Trust.  Distributable income generated by the royalty payments,
interest payments and principal repayments 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 Provident 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.
  - 11
-
 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 amounts equal to all 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 made by Provident to the Trust on notes
issued by the Trust from time to time.  It is anticipated however,
that the Trust will reinvest a portion of the repayments of principal on the
notes outstanding to enable Provident to make capital expenditures to develop or
acquire additional energy related assets to enhance cash flow from
operations.
  The Trust
seeks to provide a stable stream of 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 receipts and
payments, taxes, direct expenses of the Trust, reclamation fund contributions,
fluctuations in the demand for NGLs and natural gas, competition from other gas
processing plants, 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 Provident 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.
  8.75
Percent Debentures
  In
September 2003, the Trust issued $75.0 million aggregate principal amount of
convertible unsecured subordinated debentures.  The 8.75 Percent
Debentures mature on December 31, 2008 and bear interest at a rate of 8.75
percent per annum, payable semi-annually in arrears on June 30 and December 31
in each year.  The 8.75 Percent Debentures are convertible at the
option of the holder into Trust Units at any time prior to the earlier of
December 31, 2008 and the business day immediately preceding any date specified
by the Trust for redemption at a conversion price of $11.05 per Trust Unit,
subject to adjustment in certain circumstances.  After January 1, 2007
and prior to maturity, the Trust may redeem the 8.75 Percent Debentures in whole
or in part from time to time at a price of $1,050 per 8.75 Percent Debenture
from January 1, 2007 until January 1, 2008 and at a price of $1,025 per 8.75
Percent Debenture thereafter until maturity, in each case plus accrued and
unpaid interest.  On redemption or maturity of the 8.75 Percent
Debentures, the Trust may, subject to regulatory approval, elect to satisfy the
redemption price or principal amount by issuing Trust Units to the 8.75 Percent
Debenture holder.  As of March 19, 2008, there was $19.9 million
aggregate principal amount of 8.75 Percent Debentures outstanding.
  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.
  - 12
-
 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, 2008, 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, 2008, there was $99.0 million aggregate
principal amount of Initial 6.5 Percent Debentures outstanding.
  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 U.S. 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.
  - 13
-
 The
Canadian Credit Facility bears interest in accordance with a pricing grid based
on Provident's debt to EBITDA multiple calculated using the most recent
quarter's EBITDA on an annualized basis.  Based on Provident's EBITDA
for the year ended December 31, 2007, the interest rate pursuant to the pricing
grid in Canadian bankers acceptance plus 0.85 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.
  Provident
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, 2007, $925.3million was drawn on the
Canadian Credit Facility.
  The
Canadian Credit Facility has a revolving three year term expiring on May 30,
2010.  Provident 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 Provident 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
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 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.
  In
addition, Provident’s U.S. subsidiaries have credit facilities with a borrowing
base of U.S. $737.7 million with a syndicate of U.S. banks secured by oil and
gas assets of the subsidiaries.  Provident’s U.S. subsidiaries may
draw upon the facility by way of U.S. base rate loans, LIBOR loans or letters of
credit.  The facilities have a termination date of October 10,
2010.  At December 31, 2007, $375.4million was drawn on
these facilities.
  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.
  - 14
-
 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 Provident 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.
  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 Proxy Statement and Information Circular dated
March 27, 2008.  As of March 19, 2008, there were 1.2
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
  - 15
-
 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 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
Unitholder.  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 such legislation is
expected to result in adverse tax consequences to the Trust and 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.
  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 could 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 could: (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 may make the Trust Units
less attractive as an acquisition currency.  As a result, it may
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
original proposals indicated that there is no intention to inhibit "normal
growth" of a SIFT during the transition period, but "undue expansion" could
result in the transition period being "revisited" presumably with the loss of
the benefit to the SIFT of that transitional period.  As a result, the
adverse tax consequences associated with the SIFT Rules could be realized by the
Trust sooner than January 1, 2011.  The SIFT Rules 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 40 percent for the period from
November 1, 2006 to December 31, 2007, and 20
  - 16
-
 percent
for each 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.
  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, 2007 is approximately $1,110
million and for each of calendar 2008, 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).
  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
  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 Provident 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 Provident will take such steps as are
necessary or desirable to ensure that the Trust is not maintained primarily for
the benefit of Non-Residents.
  Provident
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
  - 17
-
 other
steps specified by Provident, 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 Provident, 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 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 Provident 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 Provident with satisfactory evidence that such Trust
Units are not beneficially owned by Non-Residents within such period, Provident
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 Provident 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.
  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".
  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.
  - 18
-
 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 to
develop in such notes. Notes will not be qualified investments for trusts
governed by registered retirement savings plans, registered retirement income
funds and deferred profit sharing plans.
  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;
  - 19
-
 ·
              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.
  Provident
Energy Ltd.
  The
principal business of Provident 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. Provident is also engaged in
the acquisition, exploitation, development and production of crude oil and
natural gas in the Western Canadian Sedimentary Basin.  Provident
currently has 670 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, California and Wyoming 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 Provident has generally been delegated the significant
management decisions of the Trust.  In particular, the Trustee has
delegated to Provident 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 Provident
pursuant to the terms of the Unanimous Shareholder Agreement.
  Decision
Making
  The board
of directors of Provident supervises the management of the business and affairs
of the Trust, including the business and affairs of the Trust delegated to
Provident.  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 Provident.  In addition, the Trustee has
delegated certain matters to the board of directors of Provident 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
Provident on behalf of the Trust.  The board of directors of Provident
generally holds regularly scheduled meetings to review the business and affairs
of Provident and make any necessary decisions relating thereto.
  - 20
-
 Common
Shares
  All of
the issued and outstanding common shares of Provident are held by the Trust.
Each common share of Provident entitles its holder to receive notice of and to
attend all meetings of the shareholders of Provident and to one vote at such
meetings.  The holders of the common shares are, at the discretion of
the board of directors of Provident 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
to share equally in any distribution of the assets of Provident upon the
liquidation, dissolution, bankruptcy or winding-up of Provident or 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 Provident.  Any
decision to pay dividends on the common shares of Provident in the future will
be made by the board of directors of Provident on the basis of Provident's
earnings, financial requirements and other conditions existing at the
time.
  Royalties
  Provident
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
Provident.
  Provident
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 Provident.
  Provident
is required to establish a reserve to fund future well bore and facility
abandonment and environmental and reclamation obligations and liabilities (the
"Reclamation Fund").  Provident currently funds this reserve at $0.30
per barrel of oil equivalent (converting gas to oil at 6:1) (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, Provident has issued notes to the Trust in connection with certain
acquisitions and other transactions undertaken by the Trust.  Cash
flow from Provident's producing properties distributed from Provident to the
Trust includes interest payments and principal repayments on the various notes
held by the Trust.  In addition, cash flow from the natural gas
midstream, NGL processing and marketing business flows from PMI to the Trust by
way of interest payments and principal repayments on notes issued to the
Trust.
  Provident
Holdings Trust, Provident Acquisitions L.P., Provident Marketing L.P. and
Provident Midstream L.P.
  Provident
Acquisitions L.P. holds certain southeast Alberta properties and heavy oil
wells.  Holdings Trust holds all limited growth units in Provident
Midstream L.P., and a 99 percent interest in Provident Marketing L.P. and
Provident Acquisitions L.P. and is managed by Provident.  Holdings
Trust is wholly-owned by the Trust.  The general partner of Provident
Acquisitions L.P. is Provident.  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.  The general partner of Provident Marketing L.P. is
Provident Marketing Inc. and the general partner of Provident Midstream L.P. is
Provident GP Inc.  Provident Midstream L.P. holds, either directly or
indirectly through partnerships, all of the assets located in Canada
  - 21
-
 acquired
as a result of the Midstream NGL Acquisition, other than minor general
partnership interests held by Provident GP Inc., a wholly-owned subsidiary of
Provident.  Cash flow from these assets flows to Holdings Trust by way
of distributions on limited partnership units and from Holdings Trust to the
Trust by way of interest and principal payments on notes issued by Holdings
Trust to the Trust.
  Provident
Energy Resources Inc.
  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 holds
certain Alberta and Saskatchewan properties that were acquired through the
purchase of Meota Resources Corp.  PAI is managed by Provident 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.  Provident
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.
  Provident
Midstream Inc.
  PMI holds
the Redwater Midstream NGL Assets and 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 the Trust.
  Pro
Holding Company
  PHC owns
all of the outstanding shares of Pro LP Corp. and Pro GP Corp. which in turn own
approximately96
percentof the
outstanding partnership interests in BEC L.P. and approximately 22 percent of
the outstanding partnership interests of BreitBurn MLP.  PHC also 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 all of the common shares
of PMI.
  BreitBurn
Energy Company L.P.
  BEC L.P.
holds certain of the oil and gas properties in California acquired pursuant to
the BreitBurn Acquisition and the Orcutt Hill Properties acquired pursuant to
the Orcutt Hill Acquisition.  The Trust currently indirectly holds
approximately 96 percent of the outstanding partnership interests of BEC L.P.
with the remaining approximately 4 percentof the partnership
interests held by BreitBurn's co-founders and co-chief executive
officers.  Cash flow from the oil and gas properties and related
tangibles held by BEC L.P. is distributed to BEC L.P.'s partners, BreitBurn
Energy Corporation, Pro LP Corp. and Pro GP Corp. and from Pro LP Corp. and Pro
GP Corp. to the Trust in the form of dividends, debt repayments and interest
payments on intercompany debt.
  BEC L.P.
continues to operate and report as a business line of the Trust.
  - 22
-
 BreitBurn
Energy Partners L.P.
  The
assets of BreitBurn MLP consist primarily of crude oil reserves in the Los
Angeles basin in California and the Wind River and Big Horn basins in central
Wyoming, as well as Texas and Florida, and gas reserves in Michigan, Indiana and
Kentucky.  BreitBurn MLP also holds the membership interests of
Nautilus, which holds oil and gas producing properties in the State of
Wyoming.  BreitBurn MLP is a publicly traded master limited
partnership managed by its general partner, BreitBurn GP LLC, whose board of
directors consists of 3 directors or officers of Provident and 4 independent
directors.
  The Trust
indirectly holds approximately 22 percent of the outstanding partnership
interests in BreitBurn MLP.  The co-founders and co-chief executive
officers of BEC L.P. hold approximately 1 percent of the partnership interests
in BreitBurn MLP, with the public holding the remaining 77 percent of the
partnership interests in BreitBurn MLP.  The limited partnership units
are listed for trading on the NASDAQ.
  Cash flow
from the assets held by BreitBurn MLP is distributed to Pro LP Corp. and Pro GP
Corp. and from Pro LP Corp. and Pro GP Corp. to the Trust (via PHC) in the form
of dividends, debt repayments and interest payments.
  GENERAL
DEVELOPMENT OF THE BUSINESS OF THE TRUST AND PROVIDENT
  The
following information describes the development of the business of the Trust and
its material subsidiaries over the last three completed financial
years.
  On
February 9, 2005, BEC L.P., entered into a membership interest purchase and
sale agreement with all of the holders of membership interests in Nautilus
pursuant to which BEC L.P. agreed to acquire all membership interests in
Nautilus for an aggregate purchase price of US$75.0 million, subject to
adjustment.  The Nautilus Acquisition was completed on March 2,
2005.
  In
connection with the Nautilus Acquisition, the Trust completed a public offering
on March 1, 2005 of 8,400,000 Trust Units and $100.0 million aggregate
principal amount of Initial 6.5 Percent Debentures for gross proceeds of $200.0
million.  The net proceeds from the offering were used to fund the
Nautilus Acquisition, to fund the Trust's capital expenditure program and for
general corporate purposes.
  On March
11, 2005, the Trust announced the appointment of Mr. Hugh A. Fergusson to the
Board of Directors of Provident.
  On May
31, 2005, all outstanding 10.5 percent convertible unsecured subordinated
debentures of the Trust (the "10.5 Percent Debentures"), were redeemed at an
amount of $1,050 plus all accrued and unpaid interest to May 30, 2005 per each
$1,000 principal amount of 10.5 Percent Debenture. An aggregate of $3.0 million
was paid on redemption of the 10.5 Percent Debentures.  An aggregate
of 3,507,570 Trust Units were issued upon conversion of the then outstanding
10.5 Percent Debentures prior to the redemption of such debentures.
  On June
28, 2005, the Trust announced that Mr. Daniel J. O'Byrne was appointed to the
newly created position of Executive Vice-President, Operations and Chief
Operating Officer.  Mr. O'Byrne is responsible for Provident's oil and
gas production and its midstream operations.
  On
October 3, 2005, the Trust announced that Mr. Grant D. Billing was stepping down
as Chairman of the board of directors of Provident.  Mr. John B.
Zaozirny, Q.C., was appointed to replace Mr. Billing as the Chairman of the
board of directors of Provident.  Provident's board believes the
regular rotation of the Chairman of the board of directors and Chairs of board
committees is good governance practice.  Mr. Billing continues to be a
director of Provident.
  On
October 20, 2005, the Trust signed an agreement with a large oil and gas company
to provide rail offloading and terminalling services for condensate to be used
as a heavy oil diluent.  A new condensate offloading facility was
built at Provident's NGL fractionation plant at Redwater,
Alberta.  The existing Redwater plant has been expanded to offload and
re-deliver an additional 60,000 barrels per day of condensate for the
counterparty and other heavy oil producers.  The expansion also
included a new multi-product truck loading facility.  These new
terminals complement the existing pipeline connections to and from the plant and
were completed in the second quarter of 2006, at a total cost of approximately
$50 million.  Full utilization of this facility's capacity is expected
by management of Provident to increase the current western Canadian diluent
supply by more than 15 percent.
  - 23
-
 On
October 27, 2005, the Trust and Provident entered into a purchase and sale
agreement with EnCana Corporation, 1140102 Alberta Ltd., EnCana Midstream Inc.,
WD Energy Services Inc. and EnCana Kerrobert Pipelines Limited (collectively,
the "EnCana Vendors") pursuant to which Provident agreed to acquire certain
assets, shares and partnership interests which comprised the EnCana Vendors'
natural gas liquids business for a purchase price, net of cash acquired, of
$773.0 million. The assets of the Midstream NGL Business include interests in
certain NGL extraction plants, pipelines, storage and fractionation facilities,
distribution facilities, contracts and the EnCana Vendors' interest in the NGL
marketing business operated by 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.  The
Midstream NGL Acquisition was completed on December 13, 2005.
  In
connection with the Midstream NGL Acquisition, the Trust completed a public
offering on November 15, 2005 of 21,830,000 subscription receipts and
$150.0 million aggregate principal amount of Supplemental 6.5 Percent Debentures
for gross proceeds of approximately $425.0 million.  The net proceeds
of the Midstream NGL Acquisition were used to pay a portion of the purchase
price in respect of the Midstream NGL Acquisition.  Each subscription
receipt was automatically exchanged for one Trust Unit upon closing of the
Midstream NGL Acquisition.
  In the
fourth quarter of 2005, the Trust expanded its term credit facilities from
$410.0 million at December 31, 2004.  The expanded facilities are
comprised of $750.0 million of lending capacity related to its Canadian assets
and US$100.0 million of lending capacity related to its U.S.
assets.  The facilities are separate and each is provided by separate
syndicates of banks.
  On
December 16, 2005, the Trust Units were listed on the NYSE under the symbol
"PVX" and the Trust discontinued the listing of the Trust Units on the
AMEX.
  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 consist 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 continues to
operate both BreitBurn MLP and BEC L.P.  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.
  - 24
-
 Effective
June 30, 2006, Randall J. Findlay, the President of Provident, retired from his
management responsibilities with Provident.  Mr. Findlay remains on
the board of directors of Provident.  Thomas W. Buchanan, the Chief
Executive Officer of Provident, was also appointed President of Provident
following Mr. Findlay's resignation.
  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.
  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 Capital Shares, at a price of $8.16 in cash for
each Capitol Share.
  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
  - 25
-
 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.".
  The total
cash amount paid by the Trust to purchase all of the outstanding Capitol Shares
was approximately $466 million.  The Trust also assumed Capital'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 continues 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 has also been 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.
  The Trust
has initiated a strategic review process for its U.S. operations which will
assess, among other things, the possible sale of the BreitBurn MLP master
limited partnership units owned by the Trust, as well as the Trust's interest in
BreitBurn GP LLC ("the General Partner"), the general partner of BreitBurn MLP
and also its interest in BEC L.P.  The Trust currently owns
approximately 14.8 million units or approximately 22% of BreitBurn MLP including
units held by the General Partner of which the Trust indirectly owns
approximately 96%.  The Trust, through a wholly owned subsidiary,
indirectly owns
  - 26
-
 approximately
96% of BEC L.P.  The strategic review process will be ongoing and
while it is the Trust's intention to monetize its U.S. investment, there is no
certainty that this process will result in any changes to the Trust's ownership
stake in its U.S. holdings.  The Trust has retained a financial
advisor in connection with its strategic review process.
  The Trust
delivered an offer to BreitBurn MLP providing BreitBurn MLP the opportunity to
acquire BEC L.P. as an initial step in its strategic review
process.  The offer was delivered in accordance with the Trust's
obligations to BreitBurn under an omnibus agreement between the Trust and
BreitBurn MLP.  The offer formally expired and the Trust expects to
initiate a formal auction sales process respecting BEC L.P., all in accordance
with the omnibus agreement.
  The Trust
continues to assess its business plans and corporate structure as part of its
overall planning in order to optimize business performance, facilitate business
growth, improve overall access to capital and enhance the cost of capital for
the Trust's businesses.  This planning is also required to respond to
the challenges arising from 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.
  The Trust
intends through this planning initiative to consider the most viable strategic
and structural options available to the Trust with the objectives of capturing
and protecting unitholder value going forward.  Certain options under
consideration include the separation of the oil and natural gas production and
the midstream components of the Trust's Canadian business.  The
possible separation of the upstream and midstream businesses or other
alternatives reflect the Trust's view that the full value of the component parts
of the business are not currently being realized in the market.  The
Trust cautions that the planning required before implementation of any plans
will be lengthy and complex and there is no certainty that the planning will
result in significant changes to the Trust.
  The
Trust's planning initiatives will not impact the Trust's capital program, budget
or guidance.  The Trust believes the initiative confirms its belief in
the high quality of its asset base, the strength of its operations and the
excellence of its people.  Accordingly, throughout the planning
initiative, the Trust will operate its Canadian businesses in the ordinary
course and continue to execute its business plan and to assess and undertake
strategic growth initiatives.
  RISK
MANAGEMENT
  General
  Provident's
strategy is focused on achieving a consistent level of monthly cash
distributions to the Unitholders.  To this end, Provident pursues a
balanced portfolio strategy that incorporates the integration of the oil and gas
production business and the natural gas midstream, NGL processing and marketing
business.  This balanced portfolio extends the economic life of the
Trust, assists with the stability of cash flows and provides Provident access to
a broader range of opportunities across the energy value chain.
  With
respect to the oil and gas production business, Provident is focused on the
acquisition, development, exploitation, production and marketing of crude oil
and natural gas.  Provident's energy portfolio is located in some of
the most stable and predictable producing regions in Western Canada and the
United States.  In management's opinion, these areas generally offer
low to medium risk development potential and a well developed operational
infrastructure, which is suited to a trust.  Provident focuses its
development activities on low risk drilling opportunities that can be used to
partially offset production declines.
  Provident's
natural gas midstream, NGL processing and marketing business adds an additional
dimension to the Trust – one with relatively small maintenance capital
requirements.  This provides the Trust with more stable, longer
life cash flows and provides the Trust access to a broader range of growth
opportunities along the energy value chain.
  - 27
-
 A
disciplined integrated risk management strategy is employed by Provident,
focusing on stabilizing cash flow.  To this end, Provident uses both
financial and physical contracts to reduce the volatility of crude, natural gas
and NGL prices.
  Risk
Management
  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 Board of
Directors.
  Provident’s
Risk Management group monitors risk exposure by generating and reviewing
counterparty credit exposure and mark-to-market reports of its outstanding
derivative contracts.  Provident’s monitoring activities also include
reviewing available hedging structures, regulatory changes and bank, analyst and
legal reports.
  The
status of key risk exposures is regularly communicated to Provident’s executive
and business lines. External audiences receive regular risk updates through
quarterly and annual reports.
  Commodity
Price Risk Management Program
  The
decisions to enter into hedge positions and to execute 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 Hedging
  Provident’s
hedging program employs derivative instruments, such as puts, participating
swaps and costless collars, to protect a floor level of Provident’s EBITDA
(earnings before interest, taxes, depletion, depreciation, accretion and other
non-cash items) on a portion of the oil and gas sold.  At the same
time, these instruments enable Provident to retain various levels of
participation to the extent oil and gas prices rise.  Provident may
also use fixed price derivative instruments for its oil and natural gas business
lines to protect acquisition economics.
  The major
identified risks for the oil and natural gas business lines (COGP and USOGP) are
commodity price volatility and market location differentials. Provident
addresses these risks using a hedging program designed to protect a portion of
its cash flow in order to support continued unitholder distributions, capital
programs and bank financing.
  Midstream
Services
  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 spreads. Frac spread is the margin between the
price paid for the natural gas feedstock from which Provident extracts NGLs, and
the absolute price at which Provident sells NGL products (propane, butane and
condensate).
  - 28
-
 Provident
responds to these risks using a hedging program that protects a margin or floor
level of EBITDA on a portion of its NGL inventory and production, while
retaining some ability to participate in a widening margin
environment.  For longer-term hedges, Provident hedges crude oil in
place of NGLs. Provident may replace these hedges with actual NGL hedges as
market conditions allow. This strategy enables Provident to mitigate commodity
price risk related to its NGL production business up to five years into the
future.
  Foreign
Currency & Interest Rates
  Provident
receives both Canadian and U.S. dollars for oil, natural gas and NGL sales,
exposing it to both positive and negative effects of fluctuations in the
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 U.S. and Canadian business lines. Provident
can also manage the associated risk of higher interest rates using derivative
instruments.
  Provident’s
foreign exchange hedging strategy reduced the effect of the 13 percent
appreciation of the Canadian dollar relative to the U.S. dollar in
2007.  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
insurance against a stronger Canadian dollar, while allowing it to participate
if the currency weakens relative to the U.S. dollar.
  Power
  Power is
a significant cost to Provident.  Provident manages volatile power
costs by purchasing derivative contracts that fix the cost of power for a
pre-determined time period.
  Details
of the financial instruments in place at December 31, 2007 are summarized in
Note 13 to the Trust's audited consolidated financial statements for the year
ended December 31, 2007 and are incorporated by reference herein.  The
Trust's audited consolidated financial statements for the year ended December
31, 2007 have been filed on SEDAR and are available under the Trust's issuer
profile at www.sedar.com.
  Credit
Risk
  Provident's
Credit Policy governs the activities undertaken to mitigate the risks associated
with counterparty (customer) non-payment.  A formal credit review is
required for counterparties entering into a commodity contract with
Provident.  This review determines an approved credit
limit.  Counterparty exposures are regularly monitored and an annual
review of all active counterparties is performed.  In addition, the
policy sets criteria to ensure that Provident has a diversified base of
creditors.
  Insurance
  Provident
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 & officers insurance.
  - 29
-
 OIL
AND NATURAL GAS OPERATIONS
  Provident's
Canadian reserves were evaluated by McDaniel and AJM effective December 31,
2007, in accordance with NI 51-101.  Provident's U.S. reserves were
evaluated by NSAI and Schlumberger effective December 31, 2007 in accordance
with NI 51-101.  McDaniel, AJM, NSAI and Schlumberger are independent
qualified reserves evaluators appointed pursuant to NI 51-101.  The
McDaniel evaluation report is dated February 15, 2008 with a preparation date of
December 31, 2007.  The AJM evaluation report is dated February 21,
2008 with a preparation date of December 31, 2007.  The Schlumberger
evaluation report is dated February 29, 2008 with a preparation date of December
31, 2007.  The NSAI evaluation report is dated February 25, 2008 with
a preparation date of December 31, 2007.
  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, AJM, NSAI and
Schlumberger dated February 15, 2008, February 21, 2008, February 25, 2008 and
February 29, 2008, respectively and the Report of Management and Directors on
Oil and Gas Disclosure on Form 51-101F3 dated March 6, 2008 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
  General
  The
Canadian NGL industry involves the production, transportation and marketing of
products that are extracted from natural gas prior to its sale to end use
customers.  On a production basis, the Canadian industry is about one
third the size of the US industry, and Provident's natural gas midstream, NGL
processing and marketing business represents one of the five largest NGL
production asset groupings in North America.  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.  In Canada, approximately 90 percent of NGLs are a by-product of
natural gas processing, with 10 percent resulting from the refining of crude
oil.  Approximately 75 percent of NGL production in Canada results
from natural gas production in Alberta.
  The NGL
value chain begins with the gathering of gas that is produced.  The
gas then gets processed through processing plants, 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.
  - 30
-
 
  NGL
Extraction
  The heart
of the NGL value chain lies in 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.  Most field plants do not remove ethane, but there is
currently about 70,000 b/d of ethane produced from Alberta field plants out of a
total 240,000 b/d of ethane production from western Canada.  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. Approximately 40 percent of the 700 field plants in western
Canada extract NGLs.
  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 (although there is some fractionation
capacity at certain field plants in Alberta).  The NGL mixes are moved
by truck or pipeline to fractionation centres, with the greater Edmonton region
serving as the major fractionation centre in Alberta and one of the four main
fractionation hubs in North America, along with Sarnia, Ontario, Conway, Kansas
and Mont Belvieu, Texas.  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.  Provident has the capacity to move
NGLs throughout North America via pipeline, truck or rail.  In
addition to its extensive pipeline network, Provident has long term leases on
approximately 835 rail cars.
  - 31
-
 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 depending on market needs); (ii) allowing NGL
providers to store inventory to accommodate outages in gas processing and NGL
fractionation plants; and (iii) exploiting seasonal price differentials
that may develop over the course of a year (particularly for propane and
butane).
  Large NGL
storage facilities in Canada are located in Sarnia and the Fort Saskatchewan /
Redwater area.  Such facilities use salt caverns deep underground
which are created by washing the salt away with water until an open space is
made.
  NGL
Marketing
  The end
uses for NGLs are abundant and expanding.  While NGLs are generally
used directly as an energy product and also as a feedstock for the petrochemical
and crude oil refining industries, the specific uses for NGLs vary substantially
by product.
  Ethane is
used primarily as feedstock for the petrochemical industry and as a miscible
flood agent for enhanced oil recovery operations.  A significant
amount of the ethane produced in the western Canadian sedimentary basin is sold
through long-term contracts for feedstock to Alberta's expanding petrochemical
industry.  The production of ethane provides a secure and stable
source of revenue and contributes to the long-term economic viability and growth
of the NGL infrastructure.
  Propane,
which makes up over 65 percent of propane-plus extracted from major extraction
facilities, 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.  Approximately
75 percent of Canadian propane is exported to the US.
  Butane,
which makes up approximately 25 percent of propane-plus produced in major
extraction facilities, is used primarily in gasoline blending or in the
production of Canadian iso-octane.  Approximately 25 percent of
Canadian butane is exported to the US.
  Pentanes-plus,
which represents less than 10 percent of propane-plus produced at major
extraction facilities, is used as a diluent to increase the viscosity of heavy
crude oil for shipping through pipelines and as a refinery feedstock to make
gasolines.  Virtually all pentanes-plus in Alberta and Saskatchewan
are used for these purposes.
  Commercial
Arrangements
  Extraction
  An
extraction facility's fees may be based either on a cost-of-service arrangement
(reimbursement for operating expenses plus a deemed return on capital employed)
or tied to production.  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.  The cost of the shrinkage make-up gas, which is
typically tied to a benchmark natural gas price, accounts for approximately 80
percent of a facility's total costs.  For the right to extract NGLs
from the gas stream, extraction facility owners generally pay shippers a premium
to the shrinkage gas price, which effectively amounts to sharing with shippers a
portion of the value that is added through the recovery and sale of
NGLs.  Other expenses include electrical power, labour, maintenance,
property taxes, insurance and other overhead.
  - 32
-
 For
ethane, market prices usually consist of a shrinkage gas cost which flows
through to ethane buyers, and an additional fixed fee to cover plant extraction
costs.  As a result, the ethane operations of an extraction facility
generally generate a relatively predictable cash flow stream.
  However,
an extraction facility's other revenues are often tied to the market prices of
propane, butane and pentanes-plus.  The majority of the facility's
costs to produce propane-plus are shrinkage gas and therefore the plant's
profitability is influenced by the relative spread between natural gas prices
and NGL product prices, often referred to as the "frac spread".  The
impact on margins can be significant when changes in the prices of NGLs and
natural gas occur at different rates or move in different
directions.
  Generally,
the commercial structure of the propane-plus business at extraction plants
offers greater leverage to a favourable shift in commodity prices than the
ethane business.  Since the prices of propane, butane and
pentanes-plus are set in the open market and are linked to the price of oil, and
the costs of these products are primarily tied to the cost of natural gas, the
profitability of a propane-plus producer is driven by the relative spread
between these two commodities.  Favourable movements in the spread
between these prices offer substantial upside to a propane-plus
producer.  Most extraction facilities have profit sharing arrangements
for propane-plus with exposure to both price and volume.  Certain
facilities have the frac spread exposure shifted onto buyers of propane-plus
through the use of cost-of-service agreements.
  Fractionation
  While
fluctuations in the frac spread are of particular importance in determining the
profitability of most extraction plants, the financial performance of
fractionation facilities is not frac spread dependent.  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 facility receives a fee for these services which varies
depending upon the complexity of the services provided.  The expense
side of the equation includes operating costs associated with gathering,
transporting, fractionating, storing and distributing the NGL
mix.  Hence, profit is earned not on the spread differential between
natural gas and NGLs, but on the difference between the fees charged and the
costs incurred for the service provided.  Alternatively, the owner of
a fractionator may purchase NGL streams in the field for its own account,
transport and process the stream, then sell the resulting products in the
Edmonton or downstream 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).
  Midstream
services and marketing assets
  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.
  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.
  - 33
-
 ·
              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, Provident holds 18.3 percent ownership of a
      300,000 barrel Superior Storage staging facility and 18.3 percent
      ownership of the 6,600 bpd Superior
  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 350 rail
cars.
  The
income for this business line is primarily driven by the pricing relationship of
natural gas at AECO to NGL values in Mont Belvieu, Texas.  Provident
purchases the NGLs from suppliers at Empress at gas values and then extracts the
NGLs from the gas at the various straddle plants.  Propane, butane and
condensate prices trend on a pricing relationship to crude
oil.  Provident sells this product and other acquired specification
product into key market areas such as Ontario, Quebec, and the Eastern
Seaboard.  The higher the ratio of the WTI crude oil price to the
natural gas price at AECO (the fractionation spread ratio "frac spread ratio"),
the higher the gross operating margin this business line will typically
deliver.  There has also, however, historically been a differential
between propane, butane and condensate prices and crude oil prices which can
change prices received and margins realized for Midstream products separate from
frac spread ratio changes.
  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.
  ·
              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
      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 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.  Provident also has long-term
      shipping rights on the Pembina Peace Pipeline that extends the product
      delivery transportation network through to the Redwater fractionation
      facility.
  ·
              A
      rail car fleet of approximately 485 rail
cars.
  The
income for this business line includes the long term natural gas liquids
purchase agreement from Taylor Gas Liquids for its share of the production at
the same plant.  Further, this business line includes the income
generated by the supply and marketing personnel in the Calgary office which
includes the
  - 34
-
 purchasing
of NGL mix from various producers transporting to Redwater/Ft. Saskatchewan for
fractionation and sale to various markets primarily in Western Canada and the
Western United States.
  The
Commercial Services business line is comprised of the following:
  ·
              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.  Further,
      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 facility, a significant portion of the available propane plus 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
also has a long term contract on a cost of service basis for the majority of its
50,000 bbl/d Empress debutantizer facility and 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 8.75
Percent Debentures, 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.A, 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)2007January
              
              $
              12.80
              
              
              $
              11.63
              
              
              
              6,255February
              
              $
              12.75
              
              
              $
              12.05
              
              
              
              4,909March
              
              $
              13.02
              
              
              $
              11.93
              
              
              
              5,366April
              
              $
              13.57
              
              
              $
              12.44
              
              
              
              6,028May
              
              $
              13.29
              
              
              $
              12.41
              
              
              
              12,590June
              
              $
              12.87
              
              
              $
              12.38
              
              
              
              10,904July
              
              $
              12.99
              
              
              $
              12.17
              
              
              
              12,893August
              
              $
              12.63
              
              
              $
              11.02
              
              
              
              13,282September
              
              $
              12.70
              
              
              $
              11.85
              
              
              
              9,723October
              
              $
              12.70
              
              
              $
              11.89
              
              
              
              10,803November
              
              $
              12.65
              
              
              $
              10.07
              
              
              
              11,194December
              
              $
              10.58
              
              
              $
              9.60
              
              
              
              13,587
  - 35
-
 
 8.75
Percent Debentures (PVE.DB.A)
 Period
              
              High
      ($)
              
              
              Low
      ($)
              
              
              Volume2007January
              
              $
              110.02
              
              
              $
              106.18
              
              
              
              580February
              
              $
              114.21
              
              
              $
              112.70
              
              
              
              1,470March
              
              $
              116.46
              
              
              $
              113.80
              
              
              
              960April
              
              $
              121.34
              
              
              $
              113.02
              
              
              
              1,950May
              
              $
              117.50
              
              
              $
              108.77
              
              
              
              760June
              
              $
              114.38
              
              
              $
              107.92
              
              
              
              200July
              
              $
              115.12
              
              
              $
              106.52
              
              
              
              51,730August
              
              $
              112.00
              
              
              $
              108.49
              
              
              
              270September
              
              $
              114.00
              
              
              $
              112.00
              
              
              
              600October
              
              $
              114.81
              
              
              $
              108.52
              
              
              
              1,940November
              
              $
              111.88
              
              
              $
              96.66
              
              
              
              2,140December
              
              $
              106.00
              
              
              $
              97.01
              
              
              
              1,860
  8
Percent Debentures (PVE.DB.B)
  Period
              
              High
      ($)
              
              
              Low
      ($)
              
              
              Volume2007January
              
              $
              106.25
              
              
              $
              105.65
              
              
              
              9,850February
              
              $
              110.00
              
              
              $
              106.50
              
              
              
              2,210March
              
              $
              110.00
              
              
              $
              106.10
              
              
              
              3,265April
              
              $
              114.99
              
              
              $
              107.54
              
              
              
              41,900May
              
              $
              108.74
              
              
              $
              105.50
              
              
              
              8,430June
              
              $
              107.84
              
              
              $
              106.00
              
              
              
              8,330July
              
              $
              108.92
              
              
              $
              105.02
              
              
              
              4,980August
              
              $
              105.00
              
              
              $
              102.00
              
              
              
              1,800September
              
              $
              106.26
              
              
              $
              103.05
              
              
              
              9,610October
              
              $
              105.78
              
              
              $
              103.22
              
              
              
              12,300November
              
              $
              103.02
              
              
              $
              97.62
              
              
              
              37,000December
              
              $
              101.47
              
              
              $
              99.35
              
              
              
              9,570
  Initial
6.5 Percent Debentures (PVE.DB.C)
  Period
              
              High
      ($)
              
              
              Low
      ($)
              
              
              Volume2007January
              
              $
              102.55
              
              
              $
              99.99
              
              
              
              25,390February
              
              $
              101.74
              
              
              $
              100.00
              
              
              
              25,350March
              
              $
              101.74
              
              
              $
              100.26
              
              
              
              54,140April
              
              $
              105.77
              
              
              $
              100.34
              
              
              
              25,630May
              
              $
              102.99
              
              
              $
              101.42
              
              
              
              32,420June
              
              $
              102.75
              
              
              $
              101.04
              
              
              
              6,560July
              
              $
              102.25
              
              
              $
              99.51
              
              
              
              7,340August
              
              $
              100.48
              
              
              $
              97.00
              
              
              
              31,050September
              
              $
              99.25
              
              
              $
              98.00
              
              
              
              10,060October
              
              $
              100.99
              
              
              $
              97.26
              
              
              
              33,560November
              
              $
              99.74
              
              
              $
              96.00
              
              
              
              30,920December
              
              $
              96.79
              
              
              $
              90.00
              
              
              
              4,650
  - 36
-
 
 Supplemental 6.5 Percent
Debentures (PVE.DB.D)
 Period
              
              High
      ($)
              
              
              Low
      ($)
              
              
              Volume2007January
              
              $
              100.99
              
              
              $
              98.31
              
              
              
              28,965February
              
              $
              99.74
              
              
              $
              96.09
              
              
              
              18,370March
              
              $
              99.99
              
              
              $
              97.75
              
              
              
              1,630April
              
              $
              101.93
              
              
              $
              96.26
              
              
              
              93,490May
              
              $
              101.79
              
              
              $
              100.00
              
              
              
              20,480June
              
              $
              101.99
              
              
              $
              98.00
              
              
              
              22,150July
              
              $
              101.19
              
              
              $
              97.01
              
              
              
              8,320August
              
              $
              99.43
              
              
              $
              93.26
              
              
              
              7,630September
              
              $
              99.49
              
              
              $
              96.01
              
              
              
              6,930October
              
              $
              98.74
              
              
              $
              95.01
              
              
              
              10,270November
              
              $
              98.74
              
              
              $
              93.51
              
              
              
              31,890December
              
              $
              96.25
              
              
              $
              90.00
              
              
              
              44,490
  New
York Stock Exchange
  Trust
Units (PVX)
  Period
              
              High
      (U.S.$)
              
              
              Low
      (U.S.$)
              
              
              Volume
      (000's)2007January
              
              $
              10.94
              
              
              $
              9.97
              
              
              
              22,041February
              
              $
              10.89
              
              
              $
              10.34
              
              
              
              15,260March
              
              $
              11.24
              
              
              $
              10.10
              
              
              
              17,107April
              
              $
              12.08
              
              
              $
              10.76
              
              
              
              18,623May
              
              $
              12.00
              
              
              $
              11.54
              
              
              
              22,743June
              
              $
              12.20
              
              
              $
              11.61
              
              
              
              20,193July
              
              $
              12.45
              
              
              $
              11.70
              
              
              
              18,618August
              
              $
              12.00
              
              
              $
              10.00
              
              
              
              21,773September
              
              $
              12.73
              
              
              $
              11.37
              
              
              
              17,494October
              
              $
              13.25
              
              
              $
              12.12
              
              
              
              17,925November
              
              $
              13.55
              
              
              $
              10.05
              
              
              
              27,850December
              
              $
              10.55
              
              
              $
              9.65
              
              
              
              29,282
  RECORD
OF CASH DISTRIBUTIONS
  The
following table sets forth the per Trust Unit amount of monthly cash
distributions 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
              
              $1.10
  - 37
-
 Distribution
      Amount
                      (Cdn$)
                  
                  Distribution
      Amount
                      (US$)(1)
 2005January
      - December
              $1.44
              
              $1.202006January
      - December
              $1.44
              
              $1.262007January
      - December
              $1.44
              
              $1.352008January
              $0.12
              
              $0.12February
              $0.12
              
              $0.12March
              $0.12
              
              $0.12Total
      to date for 2008
              $0.36
              
              $0.36
 
 Since its
inception, the Trust has paid an aggregate of $12.75 (U.S.$9.67) in cash
distributions to Unitholders.
  Note:
 (1)
              The
      exchange rate is based on the Bank of Canada noon rate on the payment
      date.
  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 2006.
  - 38
-
 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
      Price14-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
              $9.860815-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
              $11.749713-Jan-07
              $0.12
              $0.1224
              $12.2272
              $11.615815-Dec-06
              $0.12
              $0.1224
              $12.6249
              $11.993715-Nov-06
              $0.12
              $0.1224
              $12.1807
              $11.571714-Oct-06
              $0.12
              $0.1224
              $12.7208
              $12.084815-Sept-06
              $0.12
              $0.1224
              $14.0002
              $13.300215-Aug-06
              $0.12
              $0.1224
              $13.9400
              $13.243015-Jul-06
              $0.12
              $0.1224
              $13.8654
              $13.172115-Jun-06
              $0.12
              $0.1224
              $13.7283
              $13.041913-May-06
              $0.12
              $0.1224
              $13.3193
              $12.653315-Apr-06
              $0.12
              $0.1224
              $13.1042
              $12.449015-Mar-06
              $0.12
              $0.1224
              $12.3241
              $11.707915-Feb-06
              $0.12
              $0.1224
              $12.3995
              $11.779514-Jan-06
              $0.12
              $0.1224
              $12.8715
              $12.2279
 
 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 Provident, their principal position with Provident 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 8, 2008.
  - 39
-
 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
      counsel to the law firm of McCarthy Tétrault llp and Vice-Chairman of
      Canaccord Capital Corporation.  He has been a director of
      Provident since 2001 and is also a director of Bankers Petroleum Ltd.,
      Canadian Oil Sands Trust, Coastal Energy Company, Computer Modelling Group
      Ltd., Candax Inc., Fording Canadian Coal Trust, IPSCO Inc., Pengrowth
      Energy Trust and TerraVest Income Fund.
              
              60,336Grant D. Billing(2)
      of Calgary, Alberta is the Chairman and Chief Executive Officer and a
      director of Superior Plus Inc., a diversified trust, since
      1998.  He has been a director of Provident since
      2001.   He is also a director of BreitBurn Energy Partners
      LP.
              
              100,000(4)Thomas W. Buchanan of
      Calgary, Alberta has been the Chief Executive Officer and a director of
      Provident since March 2001.  Mr. Buchanan has also been the
      President of Provident 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., Athabasca
      Oilsands Corp. and BreitBurn Energy Partners LP.
              
              930,696(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 Provident since
      2005 and is also a director of Canexus Income Fund.
              
              5,000(4)Randall J. Findlay(3)of Calgary, Alberta has been a director of Provident since March
      2001.  Mr. Findlay was also the President of Provident 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, Ellis Don, Pembina Pipelines Income Fund,
      Superior Plus Inc. and BreitBurn Energy Partners LP.
              
              745,378Norman R. Gish(2)
      of Calgary, Alberta is an independent businessman.  Prior
      thereto, he was Chairman, President and Chief Executive Officer of
      Alliance Pipeline Ltd. and Aux Sable Liquid Products Inc.  He
      has been a director of Provident since 2003 and is also a director of
      Railpower Technologies Corp. and Superior Plus Inc.
              
              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
      Provident since 2001 and is also Chairman of Winstar Resources
      Ltd.
              
              140,626Dr. 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 Provident 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 Provident since 2001 and is also a director of Churchill
      Energy Inc. and BNP Resources Inc.
              
              139,610(4)Jeffrey T. Smith(2)(3)
      of Calgary, Alberta is an independent businessman.  He has been
      a director of Provident since 2001 and is also a director of Compton
      Petroleum Ltd. and Cordero Energy Inc.
              
              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 $792,000 principal amount of the Initial 6.50 Percent
      Debentures.  Mr. Buchanan also holds $100,000 of the
      Supplemental 6.50 Percent Debentures.  Mr. Fergusson 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 $20,000 principal amount of the 8.75
      Percent Debentures and also holds $110,000 principal amount of the
      Supplemental 6.50 Percent
Debentures.
  - 40
-
 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 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.
  - 41
-
 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.  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 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,
Canadian Oil and Gas Production 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.
  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, 2007, the Board of Directors had three 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.
  - 42
-
 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 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 the Trust'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. Jeffrey
T. Smith (Chairman), Mr. Grant D. Billing, Mr. Norman R. Gish 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. Byron J. Seaman, Mr. Hugh A. Fergusson and Randall J.
Findlay, all of whom are considered independent directors, other than
  - 43
-
 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,
Controller, the Senior Manager, Investor Relations and Communications and the
Assistant Corporate Secretary of Provident.  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 Provident 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 Provident 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, Provident is not aware of any existing or potential material
conflicts of interest between Provident and a director or officer of
Provident.
  - 44
-
 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 Multilateral 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:
  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.
  - 45
-
 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 2007 and
2006.  PricewaterhouseCoopers llp is independent in accordance with
the auditor's rules of professional conduct in Canada.
  (CDN$)
              
              2007
              
              
              2006Audit
      Fees
              
              $
              2,893,800
              
              
              $
              2,680,800Audit-Related
      Fees
              
              
              590,600
              
              
              
              1,244,900Tax
      Fees
              
              
              675,900
              
              
              
              1,207,500All
      Other Fees
              
              
              173,300
              
              
              
              -Total
              
              $
              4,333,600
              
              
              $
              5,133,200
 
 Audit
Fees
  Fees for
audit services totalled approximately $2.9 millionin 2007 and
approximately $2.7 million in 2006, including fees associated with the annual
audit, the reviews of the Trust's quarterly reports, statutory audits and
regulatory filings.  These fees include approximately $1.7 million in
2007 and $1.5 million in 2006 directly related to U.S.
operations.  Fees in 2007 have increased as a result of growth in the
Trust by acquisition.
  Audit-Related
Fees
  Fees for
audit-related services totalled approximately $0.6 million in 2007 and
approximately $1.2 million in 2006.  Audit related services include
consultations concerning documents filed with respect to audits in connection
with proposed or completed acquisitions and for 2007 included work related to
BreitBurn MLP.
  Tax
Fees
  Fees for
tax services totalled approximately $0.7 million in 2007 and approximately $1.2
million in 2006.  Fees for tax services include tax compliance, tax
planning and tax advice services.
  All
Other Fees
  Fees for
all other services totalled approximately $0.2 million in 2007.
  The Trust
has complied with applicable rules regulating the provision of non-audit
services to the Trust by its external auditor.  All audit and
non-audit services provided to the Trust by PricewaterhouseCoopers llp in excess
of $100,000 have been pre-approved by the Audit Committee.  The Audit
Committee has reviewed these services to ensure they are compatible with
maintaining the independence of the external auditor.
  - 46
-
 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 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.
  - 47
-
 Provincial
Royalties and Incentives
  In
addition to federal regulation, each province has legislation and regulations,
which govern land tenure, royalties, production rates, environmental protection
and other matters.  The royalty regime is a significant factor in the
profitability of 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.  On October 25, 2007,
the Government of Alberta unveiled a new royalty regime.  The new
regime will introduce new royalties for conventional oil, natural gas and
bitumen effective January 1, 2009 that are linked to price and production levels
and will apply to both new and existing conventional oil and gas activities and
oil sands projects.
  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.  Royalties payable
to the Crown in right of the Province of Alberta (the "Crown") currently are 30
and 35 percent in the case of old and new conventional oil, respectively, from 5
to 35 percent in the case of natural gas, and from 15 to 50 percent in the case
of natural gas liquids.
  Under the
new royalty regime, it is proposed that the royalty for conventional oil will be
determined based upon a sliding rate formula containing elements that account
for oil price and well production, and specialty royalty programs will be
eliminated along with "old" and "new" tiers.  Royalty rates for
conventional oil will range up to 50 percent, with rate caps once the price of
conventional oil reaches Cdn.$120 per barrel.
  Under the
new royalty regime, it is proposed that natural gas royalties will be set by a
sliding rate formula sensitive to price and well production, and vintages will
be eliminated along with certain specialty royalty programs, though a form of
deep gas royalty holiday will be retained and lower royalty rates will be
applied over a wider price range for wells with less
productivity.  Royalty rates for natural gas will range from five
percent to 50 percent with rate caps once the price of natural gas reaches
$16.59/gj.  A shallow rights reversion program will also be
implemented that will result in the reversion to the Crown in Alberta of mineral
rights to underdeveloped geological formations above developed
zones.  Royalties for natural gas liquids will be set at 40 percent
for pentanes and 30 percent for butanes and propane.
  The
implementation of the proposed changes to the royalty regime in Alberta is
subject to certain risks and uncertainties.   The significant
changes to the royalty regime require new legislation, changes to existing
regulations and development of proprietary software to support the calculation
and collection of royalties.  Additionally, certain proposed changes
contemplate further public and/or industry consultation.  There may be
modifications introduced to the proposed royalty structure prior to the
implementation thereof.
  - 48
-
 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 greenhouse gas
emissions to 6% below 1990 "business as usual" levels between 2008 and 2012.
Given revised estimates of Canada's normal emissions levels, this target
translates into an approximately 40% gross reduction in Canada's current
emissions. It remains uncertain whether the Kyoto target of 6% below 1990
emission levels will be enforced in Canada. The Federal Government has
introduced legislation aimed at reducing greenhouse gas emissions using an
"intensity based" approach, the specifics of which have yet to be determined.
Bill C 288, which is intended to ensure that Canada meets its global climate
change obligations under the Kyoto Protocol, was passed by the House of Commons
on February 14, 2007. On April 26, 2007, the Federal Government released its
Action Plan to Reduce Greenhouse Gases and Air Pollution (the "Action Plan")
also known as ecoACTION which includes the regulatory framework for air
emissions. This Action Plan covers not only large industry, but regulates the
fuel efficiency of vehicles and the strengthening of energy standards for a
number of energy using products. 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" (the "Updated Action Plan") which provides some
additional guidance with respect to the Government of Canada's plan to reduce
greenhouse gas emissions by 20% by 2020 and by 60% to 70% by 2050. The Updated
Action Plan is primarily directed towards industrial emissions from certain
specified industries including the oil sands, oil and gas and refining
industries. The Updated Action Plan is intended to force industry to reduce
greenhouse gas emissions and to create a carbon emissions trading market,
including an offset system, to provide incentives to reduce greenhouse gas
emission and establish a market price for carbon. The Updated Action Plan
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 years 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 carbon capture and storage or other
green technologies intensity. For the upstream oil and gas industry, the Updated
Action Plan also provides for a company threshold of 10,000 boe/day and facility
threshold of 3,000 tonnes of CO2.
  Environmental
legislation in the Province of Alberta has been consolidated into the Environmental Protection and
Enhancement Act(Alberta) (the "EPEA") and the Oil and Gas Conservation Act
(Alberta) (the "OGCA"). The EPEA and OGCA impose environmental standards,
require compliance, reporting and monitoring obligations, and impose penalties.
In 2006, the Alberta Government enacted regulations pursuant to the EPEA to
specifically target sulphur oxide and nitrous oxide emissions from industrial
operations including the oil and gas industry. In addition, the reduction
emission guidelines outlined in the Climate Change and Emissions Management
Amendment Act came into effect on July 1, 2007. Under this legislation, Alberta
facilities emitting more than 100,000 tonnes of greenhouse gases a year must
reduce their emissions intensity by 12%.  Companies have three options
to choose from in order to meet the reduction requirements outlined in this
legislation, and these are: (i) by making improvement to
  - 49
-
 operations
that result in reductions; (ii) by purchasing emission credits from other
sectors or facilities that have emissions below the 100,000 tonne threshold and
are voluntarily reducing their emission; or (iii) by contributing to the Climate
Change and Emissions Management Fund.  Companies can either choose one
of these options or a combination thereof. The Trust 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 EPEA and similar legislation in other 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.
  On
January 24, 2008, the Alberta Government announced a new climate change action
plan that will cut Alberta's projected 400 million tonnes of emissions in half
by 2050. This plan is based on three areas: (i) carbon capture and storage; (ii)
energy conservation and efficiency; and (iii) greening production through
increased investment in clean energy technology, as well as the funding of
projects that reduce the cost of separating CO2
from other emissions supporting carbon capture and storage.
  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.
  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
  Exploitation
and Development
  Exploitation
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.
  - 50
-
 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.
  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, NSAI, Schlumberger 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.
  - 51
-
 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 the Trust 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 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.
  - 52
-
 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.  Under U.S. GAAP, the cost ceiling is
generally lower than under Canadian GAAP because the future net cash flows used
in the United States ceiling test are discounted to a present
value.  Accordingly, Provident would have more risk of a ceiling test
write-down in a declining price environment if it reported under U.S.
GAAP.  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.
  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,
such as those proposed in Alberta’s Climate Change and Emissions Management Act,
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.
  - 53
-
 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.
  On
October 25, 2007, the Government of Alberta unveiled a new royalty
regime.  The new regime will introduce new royalties for conventional
oil, natural gas and bitumen effective January 1, 2009 that are linked to price
and production levels and will apply to oil and gas activities.
  The
Trust's reserves and future net revenues associated thereto as incorporated by
reference in this Annual Information Form do not reflect the increased royalties
contemplated by the proposed new royalty regime and, after taking the new
royalty regime into account, such values may be adversely affected.
  The
implementation of the proposed changes to the royalty regime in Alberta is
subject to certain risks and uncertainties.  The significant changes
to the royalty regime require new legislation, changes to existing legislation
and regulation and development of proprietary software to support the
calculation and collection of royalties.
  Additionally,
certain proposed changes contemplate further public and/or industry
consultation.  There may be modifications introduced to the proposed
royalty structure prior to the implementation thereof.  There are no
assurances that the proposed royal regime will be implemented in the form
proposed by the Government of Alberta.  If changes are made to the
proposed royalty regime before it is implemented, such changes could be more
adverse to Provident than the royalty regime currently proposed. 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.
  - 54
-
 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 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,
  - 55
-
 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.
  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
Midstream NGL Business' exposure to commodity price risk applies mainly to frac
spread.  The MidstreamNGL Business is exposed
to the relative price differential between the NGL produced and the shrinkage
gas used to replace the heat content removed during extraction of the NGL from
the natural gas stream.  The amount of profit or loss made on this
portion of the MidstreamNGL Business will
increase or decrease as the difference between the price of the applicable NGL
and the price of natural gas varies.  The Midstream NGL Business will
increase Provident's exposure to frac spread which could result in a material
variability of cash flow generated by the Midstream NGL Business.  Any
such variability could negatively affect the Trust and the cash distributions of
the Trust.  Frac spread is of less risk for Provident's natural gas
midstream and NGL processing business.
  Reliance
on Principal Customers and Operators
  Provident
will rely on several significant customers to purchase product from the
Midstream NGL 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
  - 56
-
 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 and will also be the principal supplier of natural gas and NGL for
the Midstream NGL Business.  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 MidstreamNGL Business could be
negatively impacted.
  General
Risk Factors
  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".  The Department of
Finance has indicated that it will be consulting with the private sector
regarding non-resident ownership of mutual fund units.  No formal
consultations have been announced in this regard.  There can be no
assurance that the treatment of mutual fund trusts will not be changed in a
manner which adversely affects Trust Unitholders.
  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.
  Availability
of Credit and Debt Service
  As of
March 19, 2008, the Trust had drawn $908.0 million against the Canadian
credit facility and had $29.6 million of the Canadian credit facility drawn
on letters of credit, representing 83 percent of the Canadian credit
capacity.  In addition, as of March 19, 2008, the Trust had drawn
US$382.0 million against the U.S. credit facility and had US$4.3 million of the
U.S. credit facility drawn on letters of credit, representing 53 percent of the
U.S. 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.
  - 57
-
 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.  In such circumstances, cash distributions may be
reduced.
   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.
  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, Provident and Certain Subsidiaries - 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
sector and should not be viewed by investors as shares in
Provident.  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 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 the Trust to acquire suitable oil and natural
gas properties.  Changes in market conditions may adversely affect the
trading price of the Trust Units.
  The Trust Units are not"deposits"within the meaning of 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.
  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.
  - 58
-
 The
operations of the Trust 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 Provident 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 Provident 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.
  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.
  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.
  In
addition, the exchange rate for the Canadian dollar versus the U.S. dollar has
increased significantly over the last 12 months, resulting in the receipt by the
Trust of fewer Canadian dollars for its production which may affect future
distributions.  Provident has initiated certain hedges to mitigate
these risks.  The increase in the exchange rate for the Canadian
dollar and future Canadian/United States exchange rates may impact future
distributions and the future value of the Trust's reserves as determined by
independent evaluators.
  - 59
-
 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 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 NSAI, independent oil and gas reservoir engineers, as a group,
do not beneficially own, directly or indirectly, any 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.  As of the date hereof, the
designated professionals of Schlumberger, 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, Provident and Certain Subsidiaries";
and (b)  the Canadian Credit Facility described herein under the heading
"Information Concerning the Trust, Provident and Certain Subsidiaries - 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
  - 60
-
 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.
  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)
296-2233.  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, 2008,the directors and senior
officers of Provident, as a group, beneficially owned, directly or indirectly,
2.3 million Trust Units or approximately 1 percentof the issued and
outstanding Trust Units.
  ADDITIONAL
INFORMATION
  Additional
information related to the remuneration of the directors and officers of
Provident for the year ended December 31, 2007, the indebtedness of the
directors and officers of Provident, 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 dated March 27, 2008, which relates to the Annual and
Special Meeting of the Unitholders to be held on May 8,
2008.  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, 2007.
  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)
      296-2233Fax:
              (403)
      261-6696
  Additional
information relating to the Trust may be found on SEDAR at
www.sedar.com.
  - 61
-
 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 Multilateral Instrument 52-110 Audit Committees
("MI 52-110"), (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.
  
 A-2
  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:
  2.
              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;
  3.
              the
      Chair of the Committee shall preside as chair at each Committee meeting
      and lead Committee discussion on meeting agenda
  items;
  4.
              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;
  5.
              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;
  6.
              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;
  7.
              every
      question at a Committee meeting shall be decided by a majority of the
      votes cast;
  
   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
  9.
              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.
  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)
              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
  (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 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;
  
   (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
  6.
              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.
  7.
              The
      performance of the Committee shall be evaluated annually by the Board
      against criteria defined in the Committee and Board
    mandates.
  8.
              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.
  9.
              The
      Committee may delegate its responsibilities to sub-committees of the
      Committee.
  
 A-8
  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.
  
   ·
              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.
  
 The
following analysis provides a detailed explanation of Provident’s operating
results for the year ended December 31, 2007 compared to the year ended December
31, 2006 and should be read in conjunction with the consolidated financial
statements of Provident. This analysis has been prepared using information
available up to March 18, 2008.
  Provident
Energy Trust has diversified investments in certain segments of the energy value
chain. Provident currently operates in three key business segments: Canadian
crude oil and natural gas production (“COGP”), United States crude oil and
natural gas production (“USOGP”), and Midstream. Provident’s COGP business
produces crude oil and natural gas from seven core areas in the western Canadian
sedimentary basin. USOGP produces crude oil and natural gas in several states
across the U. S.A.
including California, Wyoming, Texas, Florida and Michigan. 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.
  This
analysis commences with a summary of the consolidated financial and operating
results followed by segmented reporting on the COGP business unit, the USOGP
business unit and the 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.
 
 Consolidated
      funds flow from operations and cash distributionsConsolidated
                
                
                
                
                Year
      ended December 31,($
      000s, except per unit data)
                
                2007
                
                
                2006
                
                
                %
      ChangeRevenue,
      Funds Flow from Operations and DistributionsRevenue
      (net of royalties and financial derivative instruments)
                
                $
                2,167,276
                
                
                $
                2,187,253
                
                
                
                (1
                )Funds
      flow from operations
                
                $
                468,255
                
                
                $
                432,664
                
                
                
                8Per
      weighted average unit - basic and diluted (1)
                
                $
                2.04
                
                
                $
                2.20
                
                
                
                (7
                )Declared
      distributions
                
                $
                333,352
                
                
                $
                283,465
                
                
                
                18Per
      Unit
                
                
                1.44
                
                
                
                1.44
                
                
                
                -Percent
      of funds flow from operations distributed (2)
                
                
                77
                %
                
                
                67
                %
                
                
                15
 
 (1)
                Includes
      dilutive impact of unit options, exchangeable shares and convertible
      debentures.
 (2)
                Calculated
      as declared distributions to unitholders divided by funds flow from
      operations less distributions to non-controlling interests of $35.8
      million (2006 - $6.5 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.
 
 36
 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, 2007, funds flow from operations increased eight percent
or $35.6 million to $468.3 million from $432.7 million for 2006 (per unit in
2007 - $2.04; 2006 - $2.20) . COGP generated $204.3 million, USOGP $85.6
million, and Midstream $178.4 million of funds flow from operations during
2007.  During 2006 COGP generated funds flow from operations of $185.3
million, USOGP $63.0 million, and Midstream $184.4 million.
  Canadian
oil and gas operations contributed funds flow from operations of $204.3 million
in 2007, an increase of $19.0 million or 10 percent when compared with $185.3
million from 2006. The 2007 results reflect higher production from the
acquisitions of Capitol Energy Resources Ltd. (“Capitol”) on June 19, 2007 and
Triwest Energy Inc. (“Triwest”) on December 3, 2007, which are primarily
light/medium crude oil production and a full year of production from the natural
gas-weighted Rainbow assets acquired on August 31, 2006. In addition,
incremental production from capital drilling programs in the core areas and
higher realized crude oil and natural gas liquids prices contributed to the
increase in funds flow from operations. These factors were offset by natural
production declines, a lower realized natural gas price tied to the lower AECO
natural gas index price, and reduced realized gains on financial derivative
instruments compared to 2006.
  The
Midstream business unit added $178.4 million to 2007 funds flow from operations,
compared with $184.4 million recorded in the year ended December 31, 2006.
Midstream funds flow from operations reflects higher operating margins for all
three business lines within the Midstream segment, offset by realized losses on
financial derivative instruments, foreign exchange losses and higher interest
costs due to increased corporate long-term debt balances.
  The U.S.
oil and gas operations provided increased funds flow from operations of $85.6
million in 2007, compared to $63.0 million in 2006, primarily driven by
increased production due to oil and gas property acquisitions by the MLP in
2007, including the $1.5 billion USOGP natural gas asset acquisition in November
2007, partially offset by the impact of $13.9 million (2006 -$4.9 million) in
cash payments, primarily in the first quarter of 2007, for unit based
compensation related to the 2006 fiscal year. The expense was recorded as
non-cash unit based compensation in 2006 and resulted in a decrease to funds
flow from operations when paid in 2007.
 
 Declared
distributions in 2007 totaled $333.4 million, 77 percent of funds flow from
operations, after distributions to non-controlling interests of $35.8 million.
This compares to $283.5 million of declared distributions in 2006, 67 percent of
funds flow from operations, after distributions to non-controlling interests of
$6.5 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.
 
 Outlook
 
 Provident’s
upstream and midstream operations are on track for 2008, as the Trust continues
to focus on operational excellence to deliver on our base capital plan and
realize additional upside through additional opportunities available in our
asset base.
  In the
Canadian upstream business, the two acquisitions in 2007 (Capitol Energy and
Triwest), the Rainbow acquisition in 2006, and Provident’s existing assets
provide Provident with approximately 1,000 identified drilling and recompletion
opportunities. The program is well underway to drill 92 net wells in 2008, and
to undertake a further 74 recompletions and workovers, with a total $134 million
capital budget. Provident expects Canadian upstream production to average
approximately 26,000 to 28,000 barrels of oil equivalent per day (boed) in
2008.  Provident expects drilling and operating costs to ease somewhat
in 2008, as activity in the sector levels off and we realize the benefit of the
high quality assets acquired.
  The U.S.
upstream business anticipates a 2008 capital program of approximately U.S.$158
million with average production expected to be in the range of 20,900 to 22,800
boed (net of royalties). BreitBurn Energy Partners, L.P. (the “MLP”) has a
capital budget of approximately U.S.$120 million and plans to drill 206 net
wells in 2008. MLP production is expected to be in the range of 18,300 to 20,000
boed (net of royalties) in 2008.  BreitBurn Energy Company LP
(“BreitBurn”) has a capital budget of up to U.S.$38 million with plans to drill
12 net wells in 2008. BreitBurn production is expected to be in the range of
2,600 to 2,800 boed (net of royalties) in 2008.
  37
 Provident
anticipates a capital program of $43 million for the Midstream business in 2008.
Management anticipates that approximately $18 million will be invested in
ongoing development of new underground storage caverns at Redwater, and $10
million will go toward further rail yard development. The 2008 sustaining
capital budget has been raised to $13 million, and includes planned expenditures
on operated and non-operated facilities.  Assuming continued strong
market conditions, Provident anticipates another successful year in 2008 for the
Midstream business.
  On
February 5, 2008, Provident announced a strategic sales process of its U.S. oil
and gas operations. Currently Provident owns approximately 22 percent of the
MLP, including units held by the General Partner of which Provident indirectly
owns approximately 96 percent. Provident also owns, through a wholly owned
subsidiary, approximately 96 percent of BreitBurn. The book value of these
investments at December 31, 2007 was approximately $425 million and the related
tax basis is estimated
to be approximately $100 million. It is Provident’s intention to monetize its
U.S. upstream investment, but there is no certainty that this process will
result in any changes to Provident’s ownership stakes in its U.S.
holdings.
  Strategic
planning in 2008 will continue to focus on a review of Provident’s Canadian
businesses and initiatives to consider the most viable strategic and structural
options available with the objectives of capturing and protecting unitholder
value going forward.  Certain options under consideration include the
separation of the upstream and the midstream components of Provident’s Canadian
business. Provident cautions that the planning required before implementation
will be lengthy and complex. There is no certainty that the planning will result
in significant changes in Provident.
 
 DistributionsThe
      following table summarizes distributions paid as declared by the Trust
      since inception:Distribution
      AmountRecord
      Date
                Payment
      Date
                
                (Cdn$)
                
                
                (US$)*2007January
      22, 2007
                February
      15, 2007
                
                $
                0.12
                
                
                
                0.10February
      28, 2007
                March
      15, 2007
                
                
                0.12
                
                
                
                0.10March
      22, 2007
                April
      13, 2007
                
                
                0.12
                
                
                
                0.11April
      24, 2007
                May
      15, 2007
                
                
                0.12
                
                
                
                0.11May
      18, 2007
                June
      15, 2007
                
                
                0.12
                
                
                
                0.11June
      22, 2007
                July
      13, 2007
                
                
                0.12
                
                
                
                0.11July
      23, 2007
                August
      15, 2007
                
                
                0.12
                
                
                
                0.11August
      22, 2007
                September
      14, 2007
                
                
                0.12
                
                
                
                0.12September
      24, 2007
                October
      15, 2007
                
                
                0.12
                
                
                
                0.12October
      22, 2007
                November
      15, 2007
                
                
                0.12
                
                
                
                0.12November
      21, 2007
                December
      14, 2007
                
                
                0.12
                
                
                
                0.12December
      21, 2007
                January
      15, 2008
                
                
                0.12
                
                
                
                0.122007
      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, 2007 – Distributions paid as declared
                
                
                $
                12.39
                
                
                
                9.31
 
 *Exchange
rate based on the Bank of Canada noon rate on the payment date. The increase in
distributions in U.S. dollars in 2007 is due to the increase in the Canadian
dollar relative to the U.S. dollar.
  For
Canadian tax purposes, 2007 distributions were determined to be 94.8 percent
taxable and 5.2 percent tax-deferred return of capital in the hands of Canadian
unitholders.  The 2006 comparables were 93.2 percent and 6.8 percent,
respectively. Distributions received by U.S. resident unitholders in 2007 were
classified as 97.6 percent qualified dividend and 2.4 percent tax deferred
return of capital. The 2006 comparables were 97.7 percent and 2.3 percent
respectively. In both Canada and the U.S., the 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.
  38
 Taxation
of trust income
 
 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 Provident. The new
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 now 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.
  The new
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 $1.5 billion in tax pools available to claim against taxable
income (see “Taxes”). 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. Net
      incomeConsolidated
                
                
                
                
                Year
      ended December 31,($
      000s, except per unit data)
                
                2007
                
                
                2006
                
                
                %
      ChangeNet
      income
                
                $
                30,434
                
                
                $
                140,920
                
                
                
                (78
                )Per
      weighted average unit–
      basic and diluted (1)
                
                $
                0.13
                
                
                $
                0.72
                
                
                
                (82
                )
 
 (1)
                Based
      on weighted average number of trust units outstanding including the
      dilutive impact of the unit option pl an, exchangeable shares and
      convertible debentures.
 
 Consolidated
                
                
                
                
                Year
      ended December 31,($
      000s)
                
                2007
                
                
                2006
                
                
                %
      ChangeCOGP
      net income
                
                $
                45,065
                
                
                $
                83,453
                
                
                
                (46
                )USOGP
      net income
                
                
                146,389
                
                
                
                2,598
                
                
                
                5,535Total
      oil and gas net income
                
                $
                191,454
                
                
                $
                86,051
                
                
                
                122Midstream
      net (loss) income
                
                
                (161,020
                )
                
                
                54,869
                
                
                
                -Consolidated
      net income
                
                $
                30,434
                
                
                $
                140,920
                
                
                
                (78
                )
 
 Net
income for the year ended December 31, 2007 decreased to $30.4 million compared
to $140.9 million of net income in the comparable 2006 period.  On a
consolidated basis, favorable operating results were more than offset by a
$281.0 million change in unrealized loss on financial derivative instruments and
increased depletion, depreciation and accretion (DD&A) expense.
  The COGP
business segment’s net income was $45.0 million, a $38.4 million reduction
compared with the year ended December 31, 2006 net income of $83.4
million.  An increase in EBITDA was more than offset by unrealized
losses on financial derivative instruments and increased DD&A resulting from
the acquisitions of Capitol and Triwest in 2007, and the Rainbow assets in
2006.
  The
Midstream segment recorded a net loss of $161.0 million as compared to net
income of $54.9 million in the year ended December 31, 2006. The loss was
primarily attributable to the impact of the commodity price risk management
program. In 2007, Midstream generated a $76.9 million or 30 percent increase in
gross operating margin, reflecting the positive price environment. Offsetting
this was a $59.1 million increase in realized losses on financial derivative
instruments and $192.9 million in unrealized losses on financial derivative
instruments in 2007 representing a $124.6 million increase from 2006.
Additionally, the Midstream segment recognized future income tax expense of
$94.2 million, an increase of $92.7 million from 2006, primarily due to the
enactment in 2007 of legislation to tax publicly traded trusts in
2011.
 
 39
 For the
year ended December 31, 2007, USOGP net income was $146.4 million as compared to
$2.6 million in the year ended December 31, 2006. USOGP net income in 2007
includes a dilution gain of $260.3 million recognized at the time MLP units were
issued to third parties to finance growth (see note 9 to consolidated financial
statements). In addition, EBITDA increased by $19.9 million, or 26 percent,
primarily due to the USOGP natural gas asset acquisition in the fourth quarter
of 2007. Partially offsetting these factors was unrealized losses on financial
derivative instruments of $110.0 million in 2007 compared to unrealized gains of
$7.7 million in 2006.
  The
significant swing in Provident’s net income year-over-year illustrates the
extent to which net income figures are impacted by the requirement to “mark to
market” all unrealized gains and losses associated with financial derivative
instruments at a point in time and report these against current period 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 variation that is not necessarily related to current
operations.
 
 Reconciliation
of non-GAAP measure
 
 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 income before taxes and
non-controlling interests follows:
 
 EBITDA
      Reconciliation
                
                
                
                
                Year
      ended December 31,($
      000s)
                
                2007
                
                
                2006
                
                
                %
      ChangeEBITDA
                
                $
                545,096
                
                
                $
                495,889
                
                
                
                10Adjusted
      for:Cash
      interest
                
                
                (69,565
                )
                
                
                (55,891
                )
                
                
                24Unrealized
      loss on financial derivative instruments
                
                
                (324,284
                )
                
                
                (43,314
                )
                
                
                649Dilution
      gain
                
                
                260,324
                
                
                
                -
                
                
                
                -Depletion,
      depreciation and accretion andother
      non-cash expenses
                
                
                (376,192
                )
                
                
                (279,188
                )
                
                
                35Income
      before taxes and non-controlling interests
                
                $
                35,379
                
                
                $
                117,496
                
                
                
                (70
                )Reconciliation
      of funds flow from operations to distributions
                
                
                
                
                
                Year
      ended December 31,($
      000's, except per unit amounts)
                
                2007
                
                
                2006
                
                
                %
      ChangeCash
      provided by operating activities
                
                $
                464,455
                
                
                $
                414,349
                
                
                
                12Change
      in non-cash operating working capital
                
                
                (624
                )
                
                
                13,693
                
                
                
                -Site
      restoration expenditures
                
                
                4,424
                
                
                
                4,622
                
                
                
                (4
                )Funds
      flow from operations
                
                
                468,255
                
                
                
                432,664
                
                
                
                8Distributions
      to non-controlling interests
                
                
                (35,846
                )
                
                
                (6,523
                )
                
                
                450Cash
      retained for financing and investing activities
                
                
                (99,057
                )
                
                
                (142,676
                )
                
                
                (31
                )Distributions
      to unitholders
                
                
                333,352
                
                
                
                283,465
                
                
                
                18Accumulated
      cash distributions, beginning of period
                
                
                926,825
                
                
                
                643,360
                
                
                
                44Accumulated
      cash distributions, end of period
                
                $
                1,260,177
                
                
                $
                926,825
                
                
                
                36Cash
      distributions per unit
                
                $
                1.44
                
                
                $
                1.44
                
                
                
                -
 
 Proportionate
disclosures
 
 Included
in the consolidated financial results of Provident, and the USOGP segment in
particular, are the consolidated results of the MLP and BreitBurn. At December
31, 2007 Provident owned approximately 22 percent of the MLP and 96 percent of
BreitBurn. In accordance with generally accepted accounting principles in Canada
and the United States, these investments are consolidated into Provident’s
results, with 100 percent of assets, liabilities, revenues and expenses recorded
along with a corresponding non-controlling interest. In other sections of
Management’s Discussion and Analysis, information is presented in its
consolidated form to correspond with the consolidated financial statements of
Provident. This section presents a number of metrics that reflect Provident’s
proportionate interest in these investments.
  Management
uses proportionate information to analyze operating performance. The
proportionate information as presented 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. The proportionate
information as presented is not intended to be viewed as an alternative to the
corresponding measures of financial performance calculated in accordance with
Canadian GAAP.
  40
  Year
      ended December 31,Oil
      and gas production (boed)
                
                2007
                
                
                2006COGP
                
                
                26,509
                
                
                
                24,018USOGP
      (1)MLP
      (total)
                
                
                9,518
                
                
                
                1,279Less:
      Non-controlling interest
                
                
                (5,454
                )
                
                
                (434
                )Provident's
      interest
                
                
                4,064
                
                
                
                845BreitBurn
      (total)
                
                
                2,606
                
                
                
                6,442Less:
      Non-controlling interest
                
                
                (112
                )
                
                
                (287
                )Provident's
      interest
                
                
                2,494
                
                
                
                6,155Total
      USOGP - Provident's interest
                
                
                6,558
                
                
                
                7,000Total
      - Provident's interest
                
                
                33,067
                
                
                
                31,018
 
 (1)
                In
      the fourth quarter of 2006, approximately two-thirds of USOGP production
      and approximately one-half of USOGP reserves were transferred from
      BreitBurn to the MLP as part of the initial public offering of the
      MLP.
 
 Year
      ended December 31,Funds
      flow from operations ($ 000's)
                
                2007
                
                
                2006COGP
                
                $
                204,252
                
                
                $
                185,328Midstream
                
                
                178,432
                
                
                
                184,366USOGP
      (1)MLP
      (total)
                
                
                85,609
                
                
                
                12,017Less:
      Non-controlling interest
                
                
                (49,118
                )
                
                
                (4,068
                )Provident's
      interest
                
                
                36,491
                
                
                
                7,949BreitBurn
      (total)
                
                
                10,821
                
                
                
                63,555Less:
      Non-controlling interest
                
                
                (438
                )
                
                
                (2,828
                )Provident's
      interest
                
                
                10,383
                
                
                
                60,727Other
      USOGP (corporate allocations)
                
                
                (10,859
                )
                
                
                (12,602
                )Total
      USOGP - Provident's interest
                
                
                36,015
                
                
                
                56,074Total
      - Provident's interest
                
                $
                418,699
                
                
                $
                425,768
 
 (1)
                In
      the fourth quarter of 2006, approximately two-thirds of USOGP production
      and approximately one-half of USOGP reserves were transferred from
      BreitBurn to the MLP as part of the initial public offering of the
      MLP.
 
 Year
      ended December 31,Capital
      expenditures ($ 000's)
                
                2007
                
                
                2006COGP
                
                $
                146,209
                
                
                $
                70,088Midstream
                
                
                31,904
                
                
                
                66,008USOGP
      (1)MLP
      (total)
                
                
                27,936
                
                
                
                2,604Less:
      Non-controlling interest
                
                
                (15,392
                )
                
                
                (883
                )Provident's
      interest
                
                
                12,544
                
                
                
                1,721BreitBurn
      and other (total)
                
                
                41,073
                
                
                
                51,733Less:
      Non-controlling interest
                
                
                (1,769
                )
                
                
                (2,302
                )Provident's
      interest
                
                
                39,304
                
                
                
                49,431Total
      USOGP - Provident's interest
                
                
                51,848
                
                
                
                51,152Total
      - Provident's interest
                
                $
                229,961
                
                
                $
                187,248
 
 (1)
                In
      the fourth quarter of 2006, approximately two-thirds of USOGP production
      and approximately one-half of USOGP reserves were transferred from
      BreitBurn to the MLP as part of the initial public offering of the
      MLP.
 
 41
 
 As
      at December 31,Long-term
      debt - revolving term credit facilities ($ 000's)
                
                2007
                
                
                2006COGP
      (1)
                
                $
                230,999
                
                
                $
                172,980Midstream
      (1)
                
                
                692,997
                
                
                
                518,941USOGP
      (2)MLP
      (total)
                
                
                359,712
                
                
                
                1,749Less:
      Non-controlling interest
                
                
                (280,627
                )
                
                
                (593
                )Provident's
      interest
                
                
                79,085
                
                
                
                1,156BreitBurn
      (total)
                
                
                9,124
                
                
                
                9,323Less:
      Non-controlling interest
                
                
                (363
                )
                
                
                (415
                )Provident's
      interest
                
                
                8,761
                
                
                
                8,908Total
      USOGP - Provident's interest
                
                
                87,846
                
                
                
                10,064Total
      - Provident's interest
                
                $
                1,011,842
                
                
                $
                701,985
 
 (1)
                Provident's
      credit facilities have been allocated for reporting purposes as 25 percent
      COGP and 75 percent Midstream.
  (2)
                In
      the fourth quarter of 2006, approximately two-thirds of USOGP production
      and approximately one-half of USOGP reserves were transferred from
      BreitBurn to the MLP as part of the initial public offering of the
      MLP.
 
 TaxesConsolidated
                
                
                
                
                Year
      ended December 31,($
      000s)
                
                2007
                
                
                2006
                
                
                %
      ChangeCapital
      tax expense
                
                $
                3,762
                
                
                $
                1,314
                
                
                
                186Current
      and withholding tax expense
                
                
                6,362
                
                
                
                5,829
                
                
                
                9Future
      income tax expense (recovery)
                
                
                30,487
                
                
                
                (34,316
                )
                
                
                -$
                40,611
                
                
                $
                (27,173
                )
                
                
                -
 
 Capital
taxes in 2007 totaled $3.8 million, an increase from the $1.3 million expense
recorded in 2006. The increase is due to greater production subject to the
Saskatchewan resource surcharge.
  The
current and withholding tax expense of $6.4 million in 2007 compares to $5.8
million in 2006. The majority of these taxes arise from Provident’s U.S.-based
operations. The increase in current taxes was due to U.S.-based Midstream
operations. For the year ended December 31, 2007, future income tax expense was
$30.5 million, compared with a recovery of $34.3 million in 2006. The 2007
expense includes $88.4 million relating to the second quarter enactment of
legislation to tax publicly traded trusts in 2011.
  For the
year ended December 31, 2007, the total income tax expense was $40.6 million.
Based on 2007 income before taxes of $71.0 million, the expected income tax
expense was $23.3 million. The main reason for the larger than expected income
tax expense is $88.4 million of future income taxes recorded as a result of the
enactment of legislation to tax publicly traded trusts in 2011 (see “Taxation of
trust income”).  The offsetting difference between the expected
expense and the total tax expense is primarily a result of deductions allowed
when computing taxable income of the Trust for distributions made to
unitholders. The Trust is a taxable entity under Canadian income tax law and is
currently taxable only on income that is not distributed or distributable to the
unitholders. If the Trust distributes all of its taxable income to the
unitholders, no current provision for taxes is required by the Trust until 2011.
Since inception, the Trust has distributed all of its taxable income to the
unitholders.  Additionally, interest and royalties are charged by the
Trust to its subsidiaries, which are deductible in the computation of taxable
income at the incorporated subsidiary level reducing tax pool claims in certain
subsidiaries and potentiallycreating tax loss
carry-forwards that result in future income tax recoveries.
 
 42
 Provident’s
tax pools available to shelter future income as at December 31, 2007 are
estimated as follows:
 
 As
      at December 31, 2007($000s)
                
                COGP
                
                
                USOGP(1)
                
                
                Midstream
                
                
                TotalIntangibles
                
                $
                560,000
                
                
                $
                90,000
                
                
                $
                -
                
                
                $
                650,000Tangibles
                
                
                290,000
                
                
                
                65,000
                
                
                
                280,000
                
                
                
                635,000Non-capital
      losses
                
                
                165,000
                
                
                
                -
                
                
                
                20,000
                
                
                
                185,000$
                1,015,000
                
                
                $
                155,000
                
                
                $
                300,000
                
                
                $
                1,470,000(1)Non-Canadian tax pools
 
 Provident
also has capital losses of approximately $435 million which are available to
reduce the tax effect of future capital gains.
 
 Interest
      expenseConsolidated
                
                
                
                
                Year
      ended December 31,($
      000s, except as noted)
                
                2007
                
                
                2006
                
                
                %
      ChangeInterest
      on bank debt
                
                $
                49,365
                
                
                $
                34,666
                
                
                
                42Weighted-average
      interest rate on bank debt
                
                
                5.65
                %
                
                
                5.30
                %
                
                
                7Interest
      on 8.75% convertible debentures
                
                
                2,043
                
                
                
                2,573
                
                
                
                (21
                )Interest
      on 8.0% convertible debentures
                
                
                1,974
                
                
                
                2,500
                
                
                
                (21
                )Interest
      on 6.5% convertible debentures
                
                
                6,436
                
                
                
                6,437
                
                
                
                -Interest
      on 6.5% convertible debentures
                
                
                9,747
                
                
                
                9,715
                
                
                
                -Total
      cash interest
                
                $
                69,565
                
                
                $
                55,891
                
                
                
                24Weighted
      average interest rate on all long-term debt
                
                
                5.94
                %
                
                
                5.81
                %
                
                
                2Debenture
      accretion and other non-cash interest expense
                
                
                7,442
                
                
                
                6,548
                
                
                
                14Total
      interest expense
                
                $
                77,007
                
                
                $
                62,439
                
                
                
                23
 
 Interest
on bank debt increased in 2007 compared to 2006 due to increased capitalization
including debt levels that resulted from the Capitol acquisition in the second
quarter of 2007, the Rainbow asset acquisition in the third quarter of 2006 and
the USOGP natural gas asset acquisition in the fourth quarter of
2007.
 
 Financial
instruments
  Commodity
price risk management program
 
 For the
year ended December 31, 2007 $80.7 million was recorded as a realized loss on
financial derivative instruments due to the Commodity Price Risk Management
Program (the Program) with $8.0 million related to the combined oil and gas
operations and $79.0 million associated with the Midstream segment. In addition,
$6.3 million was recorded as a realized gain related to settle foreign exchange
based contracts.
  In the
oil and gas business units the realized loss in 2007 associated with crude oil
totaled $17.6 million ($2.32 per barrel) and a realized gain of $9.6 million
related to natural gas ($0.25 per gj). The combined total was a loss of $8.0
million or $0.57 per boe. In 2006 the Program recorded a realized gain of $1.9
million or $0.16 per boe with a realized loss of $5.7 million related to crude
oil ($0.97 per barrel) and a realized gain of $7.6 million related to natural
gas ($0.25 per gj).
  In 2007
the Midstream segment recorded a realized loss of $79.0 million for NGL
inventory price stabilization and frac-spread margin activities. In 2006 the
Program recorded a realized loss of $15.4 million for these activities.
  Realized
gains on foreign exchange contracts related to the Program were $6.3 million. In
2006, the Program recorded a realized gain of $0.4 million for these activities.
  On a per
trust unit basis the opportunity cost of the Program increased to $0.35 per
trust unit in 2007 from $0.07 per trust unit in 2006.
  43
 
 At
December 31, 2007 the mark to market value of open contracts was in a net loss
position of $378.0 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 2008 through January 2013, are required to be recognized in the
financial statements of Provident, affecting current period net income. These
unrealized opportunity costs relate to financial derivative instruments which
were entered into in order to manage commodity prices and protect future
Midstream product margins. 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 includes a consistent, active and
disciplined hedging program that utilizes derivative instruments to provide for
insurance against lower commodity prices and margins. The program provides
support for stable cash distributions, capital programs and bank financing. The
hedging 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 services and
marketing business unit. As well, the Provident hedging strategy reduces foreign
exchange risk due to the exposure arising from the conversion of U.S. dollars
into Canadian dollars.
  Provident
will continue to execute the program in 2008. The derivative instruments the
Trust uses include puts, calls, costless collars, participating swaps, and fixed
price products that settle against indexed referenced pricing.
  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, 2007, 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,
2007, there were no changes in Provident’s internal controls over financial
reporting that occurred during 2007 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, 2007, the company’s internal controls were found
to be operating free of any material weaknesses.
 
 Acquisitions
 
 In May
2007, BreitBurn Energy Partners L.P. (the “MLP”) completed two oil and gas
property acquisitions, one in Florida for cash consideration of USD $108.1
million and one in California for cash consideration of USD $92.5 million. The
acquisitions were financed by the issue of units by the MLP to institutional
investors. As a result of these unit issues, Provident’s interest in the MLP
decreased from approximately 66 percent to approximately 50
percent.
  On June
19, 2007, Provident acquired Capitol Energy Resources Ltd. (“Capitol”) for cash
consideration of $467.5 million. Capitol, a public oil and gas exploration and
production company active in the Western Canadian sedimentary basin, had as its
principal asset a long-life resource play at Dixonville, Alberta. This play is
being exploited using horizontal wells and will be further developed using
waterflood technology.  The acquisition was financed by the issuance
of 29,313,727 trust units at $12.75 per unit and Provident’s credit facility.
  On
November 1, 2007, the MLP acquired approximately $1.5 billion of natural gas,
crude oil and related assets in Michigan, Indiana and Kentucky from Quicksilver
Resources Inc. for U.S. $750 million in cash and approximately 21.3 million
common units of the MLP. The acquisition is comprised of natural gas-weighted
producing assets located primarily in the Michigan Antrim Shale. The cash
portion of the purchase price was funded by a private placement of new MLP units
and bank debt. As a result of this transaction, Provident’s interest in the MLP
has decreased from approximately 50 percent to approximately
22 percent.  Provident
continues to control the MLP through its 95.6 percent ownership of the general
partner, resulting in consolidation of the MLP in accordance with generally
accepted accounting principles in Canada and the United States.
  On
December 3, 2007, the Trust acquired Triwest Energy Inc. (Triwest), a privately
held company with oil assets in southeast Saskatchewan. The Trust issued 6.3
million trust units (at an ascribed value of $76.6 million) and paid $2.3
million in cash as consideration for the acquisition. Triwest provides the Trust
with approximately 1,300 barrels per day of oil production.
 
 Goodwill
 44
  Goodwill
representsthe
excess of the cost of an acquired enterprise over the net of the amounts
assigned to assets acquired and liabilities assumed. The Capitol Energy
acquisition in the second quarter of 2007 resulted in additional goodwill of
$86.0 million. In 2005, theMidstream
NGL Acquisition resulted in goodwill of $100.4 million. Goodwill of $330.9
million arose from COGP acquisitions in 2002 and 2004.
  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.
Provident engaged an independent accounting firm to assist in performing an
impairment test at year end. The impairment test includes, amongst other
variables, a comparison of the net book value of the Trust’s assets to the
market value of the Trust’s equity. Goodwill is not amortized.
 
 Liquidity
and capital resources
 
 Consolidated
                
                
                
                
                Year
      ended December 31,($
      000s)
                
                2007
                
                
                2006
                
                
                %
      ChangeLong-term
      debt - revolving term credit facility
                
                $
                1,292,832
                
                
                $
                702,993
                
                
                
                84Long-term
      debt - convertible debentures
                
                
                256,440
                
                
                
                285,792
                
                
                
                (10
                )Total
      debt
                
                
                1,549,272
                
                
                
                988,785
                
                
                
                57Equity
      (at book value)
                
                
                1,708,665
                
                
                
                1,542,974
                
                
                
                11Total
      capitalization at book value
                
                $
                3,257,937
                
                
                $
                2,531,759
                
                
                
                29Total
      debt as a percentage of total book value capitalization
                
                
                48
                %
                
                
                39
                %
                
                
                23
 
 Provident
operates three 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 at
December 31, 2007, Provident held non-bank sponsored asset-backed commercial
paper with a face value of $6.5 million.  These securities were
previously classified as a component of cash and cash equivalents on the balance
sheet. Provident has recorded an impairment write-down amounting to $1.8 million
to reflect the fair value of these assets at December 31, 2007. The write-down
is included in net income as part of foreign exchange loss and other. As at
December 31, 2007 these securities have been classified on the balance sheet as
other current assets ($1.1 million) and investments ($3.6 million) due to a
reduction in market liquidity for these investments. The resolution of the
liquidity issues will not have a significant impact on Provident’s
operations.
 
 45
  Contractual
      obligationsConsolidated
                
                
                
                
                Payment
      due by periodLess
                
                
                
                
                
                
                
                
                Morethan
      1
                
                
                1
      to
      3
                
                
                4
      to
      5
                
                
                than
      5($
      millions)
                
                Total
                
                
                year
                
                
                years
                
                
                years
                
                
                yearsLong-term
      debt - revolving term credit facilities (1)
                
                $
                1,483.4
                
                
                $
                76.1
                
                
                $
                1,407.3
                
                
                $
                -
                
                
                $
                -Long-term
      debt - convertible debentures
                
                
                343.0
                
                
                
                39.1
                
                
                
                58.0
                
                
                
                245.9
                
                
                
                -Operating
      lease obligations
                
                
                224.7
                
                
                
                20.4
                
                
                
                39.6
                
                
                
                34.4
                
                
                
                130.3Total
                
                $
                2,051.1
                
                
                $
                135.6
                
                
                $
                1,504.9
                
                
                $
                280.3
                
                
                $
                130.3
 
 (1)The
terms of the Canadian credit facility have a revolving three year period
expiring on May 30, 2010. Provident 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 Provident 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. Management intends to extend the revolving
period beyond the current maturity date.
 
 Long-term
debt and working capital
 
 As at
December 31, 2007 Provident had drawn on 71 percent of its term credit
facilities of $1,125 million and U.S. $ 737.7 million as compared to 63 percent
drawn on its $925 million and U.S. $158 million term credit facilities as at
December 31, 2006. The increase in the level of bank debt was due to the
increased scale of operations primarily due to acquisitions.
  At
December 31, 2007 Provident had letters of credit guaranteeing Provident’s
performance under certain commercial and other contracts that totaled $35.9
million, increasing bank line utilization to 72 percent. The guarantees at
December 31, 2006 totaled $31.9 million.
  Provident’s
working capital decreased by $166.3 million from $55.8 million to a deficit of
$110.5 million as at December 31, 2007.  The significant decrease is
primarily due to a $155.7 million increase in net current financial derivative
instrument liabilities, a $151.6 million increase in accounts payable including
distribution payable and current portion of convertible debentures, partially
offset by increased accounts receivable of $147.4 million.
  The ratio
of long-term debt to funds flow from operations in 2007 was 3.3 to one, compared
to 2.3 to one in 2006. Fourth quarter funds flow from operations in 2007 was
$177.6 million. The ratio
of debt to annualized fourth quarter funds flow from operations was 2.2 to one,
as compared to 2006 fourth quarter annualized debt to funds flow from operations
of 2.0 to one. The increase reflects debt issued in connection with the Capitol
Energy and USOGP natural gas asset acquisitions.
 
 Trust
units
 
 On May
24, 2007, the Trust issued 25,490,197 Subscription Receipts at a price of $12.75
per Subscription Receipt for total proceeds of $325 million ($308.3 million net
of issue costs). On June 7, 2007, an additional 3,823,530 Subscription Receipts
were issued at a price of $12.75 on exercise of the underwriter’s over-allotment
option, for additional proceeds of $48.8 million ($46.3 million net of issue
costs). Each Subscription Receipt entitled the holder to receive one trust unit
upon completion of the Capitol acquisition. The acquisition closed on June 19,
2007 at which time all the outstanding Subscription Receipts were converted into
trust units. Proceeds from the issue were used to fund the Capitol
acquisition.
  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.
  For the
year ended December 31, 2007 the Trust issued 0.5 million units on conversion of
convertible debentures (2006 – 1.3 million units). An additional 0.8 million
units pursuant to the unit option plan were issued for the year ended December
31, 2007 (2006 – 0.9 million units). Under Provident’s Premium Distribution,
Distribution Reinvestment (DRIP) and Optional Unit Purchase Plan program 4.5
million units were elected in 2007 and were issued or are to be issued
representing proceeds of $50.5 million (2006 – 3.0 million units for proceeds of
$36.9 million).
  At
December 31, 2007 management and directors held approximately 0.9 percent of the
outstanding trust units.
 
 46
 Non-controlling
interest – USOGP operations
 
 A
non-controlling interest arose from Provident’s June 15, 2004 acquisition of 92
percent of BreitBurn Energy Company L.P. (BreitBurn) of Los Angeles, California.
Additional investments since June 2004 by Provident in BreitBurn have reduced
the non-controlling interest percentage at December 31, 2007 to approximately
4.0 percent (2006 – 4.4 percent). Contributions by this non-controlling interest
were nil in 2007 (2006 – $0.5 million). At December 31, 2007 the carrying amount
of this non-controlling interest was $5.6 million (2006 - $3.9
million).
  In the
second quarter of 2006, a USOGP subsidiary began a land development project with
a partner. The subsidiary has a 20 percent interest, with the partner holding 80
percent. Because the subsidiary stands to receive a majority share of the future
proceeds, Provident is consolidating the results in its statements, with
non-controlling interest.  Contributions by the non-controlling
interest total $3.9 million in 2007 (2006 - $3.7 million). At December 31, 2007
the carrying amount of this non-controlling interest was $5.4 million (2006 -
$2.5 million).
  In the
fourth quarter of 2006, Provident’s subsidiary, BreitBurn Energy Partners, L.P.
(the “MLP”) completed its initial public offering. BreitBurn transferred oil and
gas properties comprising approximately half of its proved reserves and two
thirds of its daily production to the MLP. The offering of 6.9 million common
units at U.S. $18.50 per unit resulted in approximately 34 percent of the MLP
held by partners not related to Provident. During the second quarter of 2007,
the MLP issued 7.0 million common units to third parties for proceeds of $237.5
million. As a result of this transaction, Provident’s interest in the MLP
decreased from approximately 66 percent to approximately 50 percent, resulting
in a dilution gain of $98.6 million recorded on the consolidated statement of
operations. During the fourth quarter of 2007, the MLP issued 38.0 million units
in conjunction with the USOGP natural gas asset acquisition. The cash proceeds
and ascribed value of these issued units totaled $1,142.2 million.  As
a result of this transaction, Provident’s interest in the MLP decreased from
approximately 50 percent to approximately 22 percent, resulting in a dilution
gain of $161.7 million recorded on the consolidated statement of operations.
Provident continues to control the MLP through its 95.6 percent ownership of the
general partner. The non-controlling interest balance increased by $1,119.4
million in 2007 reflecting the non-controlling interest ownership change from
approximately 34 percent to approximately 78 percent. At December 31, 2007, the
carrying value of this non-controlling interest was $1,089.1 million (2006 -
$74.7 million).
 
 Year
      ended December 31,Non-controlling
      interests - USOGP ($ 000s)
                
                2007
                
                
                2006Non-controlling
      interests, beginning of year
                
                $
                81,111
                
                
                $
                11,885Net
      (loss) income attributable to non-controlling interest
                
                
                (35,666
                )
                
                
                2,995Distributions
      to non-controlling interest
                
                
                (35,846
                )
                
                
                (6,523
                )Investments
      by non-controlling interest
                
                
                1,129,073
                
                
                
                72,754Foreign
      currency translation adjustment
                
                
                (38,536
                )
                
                
                -Non-controlling
      interests, end of year
                
                $
                1,100,136
                
                
                $
                81,111Accumulated
      (loss) income attributable to non-controlling interest
                
                $
                (30,152
                )
                
                $
                5,514
 
 47
 
 Capital
      expenditures and fundingConsolidated
                
                
                
                
                Year
      ended December 31,($
      000s)
                
                2007
                
                
                2006
                
                
                %
      ChangeCapital
      Expenditures and FundingCapital
      ExpendituresCapital
      expenditures and reclamation fund contributions
                
                $
                (251,546
                )
                
                $
                (193,183
                )
                
                
                30Property
      acquisitions, net
                
                
                (1,028,853
                )
                
                
                (481,625
                )
                
                
                114Corporate
      acquisitions
                
                
                (469,795
                )
                
                
                (1,036
                )
                
                
                45,247Net
      capital expenditures
                
                $
                (1,750,194
                )
                
                $
                (675,844
                )
                
                
                159Funded
      ByFunds
      flow from operations net of declared distributions to unitholders and
      non-controlling
      interest
                
                $
                99,057
                
                
                $
                142,676
                
                
                
                (31
                )Increase
      in long-term debt
                
                
                534,215
                
                
                
                117,385
                
                
                
                355Issue
      of trust units, net of cost; excluding DRIP
                
                
                362,418
                
                
                
                220,225
                
                
                
                65DRIP
      proceeds
                
                
                50,491
                
                
                
                36,851
                
                
                
                37Contributions
      by non-controlling interests
                
                
                683,100
                
                
                
                135,829
                
                
                
                403Change
      in working capital, including cash, sale of assets and change
      ininvestments
                
                
                20,913
                
                
                
                22,878
                
                
                
                (9
                )Net
      capital expenditure funding
                
                $
                1,750,194
                
                
                $
                675,844
                
                
                
                159
 
 Capital
expenditures were funded by a combination of funds flow from operations, debt
and equity issued from treasury through public offerings, the DRIP program and
contributions by non-controlling interest.
  Provident
expects approximately $23 million in leasehold improvements and furniture and
equipment associated with the head office move in 2008. Up to December 31, 2007,
$20.9 million has been incurred. Of this amount, $13.6 million has been
allocated to the COGP business unit and $7.3 million has been allocated to
Midstream. See individual operating segment sections for discussion of other
capital expenditures.
 
 Non-cash
unit based compensation
 
 Non-cash
unit based compensation includes expenses or recoveries associated with
Provident’s restricted and performance unit plan, unit option plan, unit
appreciation rights and other unit based compensation plans. 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 associated with each period is recorded as non-cash
unit based compensation (a component of general and administrative expense). A
portion is also allocated to operating expense. For the year ended December 31,
2007, Provident recorded unit based compensation expense of $30.9 million (2006
- $29.7 million) and made related cash payments of $15.7 million (2006 - $5.6
million).  At December 31, 2007, the current portion of the liability
totaled $22.2 million (December 31, 2006 - $18.2 million) and the long-term
portion totaled $20.8 million (December 31, 2006 - $16.3 million).
 
 48
  COGP
      segment reviewCrude
      oil and liquids priceCOGP
                
                
                
                
                Year
      ended December 31,($
      per bbl)
                
                2007
                
                
                2006
                
                
                %
      ChangeOil
      per barrelWTI
      (US$)
                
                $
                72.31
                
                
                $
                66.22
                
                
                
                9Exchange
      rate (from US$ to Cdn$)
                
                $
                1.07
                
                
                $
                1.13
                
                
                
                (5
                )WTI
      expressed in Cdn$
                
                $
                77.67
                
                
                $
                74.83
                
                
                
                4Realized
      pricing before financial derivative instrumentsLight/Medium
      oil
                
                $
                60.38
                
                
                $
                57.18
                
                
                
                6Heavy
      oil
                
                $
                41.85
                
                
                $
                36.80
                
                
                
                14Natural
      gas liquids
                
                $
                55.07
                
                
                $
                51.91
                
                
                
                6Crude
      oil and natural gas liquids
                
                $
                56.54
                
                
                $
                52.38
                
                
                
                8The
      above realized prices are net of transportation expense.
 
 For the
year ended December 31, 2007 COGP’s realized crude oil and natural gas liquids
price, prior to the impact of financial derivative instruments, increased by
eight percent to average $56.54 compared to $52.38 in 2006. The 2007 increase
related to a nine percent higher US$ WTI crude oil price, narrower pricing
differentials on all crude oil streams and a reduction in Provident’s heavy oil
volumes as a percentage of its oil production mix price, partially offset by a
stronger Canadian dollar.
 
 Natural
      gas priceCOGP
                
                
                
                
                Year
      ended December 31,($
      per mcf)
                
                2007
                
                
                2006
                
                
                %
      ChangeAECO
      monthly index (Cdn$ per mcf)
                
                $
                6.59
                
                
                $
                6.98
                
                
                
                (6
                )Corporate
      natural gas price per mcf before financial derivative instruments
      (Cdn$)
                
                $
                6.42
                
                
                $
                6.66
                
                
                
                (4
                )
 
 The above
prices are net of transportation expense.
 
 For the
year ended December 31, 2007 COGP’s realized natural gas price, excluding
financial derivative instruments, decreased four percent as compared to 2006,
comparable to the decrease in the benchmark AECO monthly index price. Provident
markets approximately 25 percent of its natural gas to aggregators and the
remaining 75 percent is sold to the market on daily or monthly indices,
receiving prices that are based on the heat content of the natural gas.
Provident’s realized prices and changes in prices will therefore differ from
benchmark indices.
 
 ProductionCOGP
                
                
                
                
                Year
      ended December 31,2007
                
                
                2006
                
                
                %
      ChangeDaily
      productionCrude
      oil - Light/Medium (bpd)
                
                
                7,876
                
                
                
                6,815
                
                
                
                16-
      Heavy (bpd)
                
                
                1,921
                
                
                
                2,057
                
                
                
                (7
                )Natural
      gas liquids (bpd)
                
                
                1,316
                
                
                
                1,401
                
                
                
                (6
                )Natural
      gas (mcfd)
                
                
                92,378
                
                
                
                82,469
                
                
                
                12Oil
      equivalent (boed) (1)
                
                
                26,509
                
                
                
                24,018
                
                
                
                10(1)Provident reports equivalent production converting natural gas to
      oil on a 6:1 basis.
 
 For the
year ended December 31, 2007, COGP production averaged 26,509 boed, a 10 percent
increase compared to 24,018 boed in 2006.  The increase is primarily a
result of the two recent acquisitions, Capitol on June 19, 2007 and Triwest on
December 3,
  49
 2007, the
full year effect in 2007 of the acquisition of the Rainbow assets (Northwest
Alberta) on August 31, 2006, and the production volumes added through drilling
and optimization activities, partially offset by natural production declines.
The Capitol acquisition became COGP’s newest core area, Dixonville, and the
Triwest acquisition has been rolled up into the Southeast Saskatchewan core
area.
  Production
for 2007 was weighted 58 percent natural gas, 35 percent medium/light crude oil
and natural gas liquids and seven percent heavy oil. This compared to 2006
production weighted 57 percent natural gas, 34 percent medium/light oil and
natural gas liquids and nine percent heavy oil. Year-over-year, the change in
mix reflected the two acquisitions of Capitol on June 19, 2007 and Triwest on
December 3, 2007 which were primarily light/medium crude oil production, and the
full year effect in 2007 of the August 31, 2006 acquisition of the Rainbow
assets, which were primarily natural gas.
 
 COGP’s
      production summarized by core areas is as follows:Year
      ended December 31,COGP
                
                2007
                
                
                2006
                
                
                %
      ChangeDaily
      Production - by area (boed) (1)West
      Central Alberta
                
                
                6,997
                
                
                
                8,168
                
                
                
                (14
                )Southern
      Alberta
                
                
                5,622
                
                
                
                6,237
                
                
                
                (10
                )Northwest
      Alberta
                
                
                4,905
                
                
                
                1,545
                
                
                
                217Dixonville
      (2)
                
                
                2,058
                
                
                
                -
                
                
                
                -Southeast
      Saskatchewan
                
                
                1,769
                
                
                
                1,731
                
                
                
                2Southwest
      Saskatchewan
                
                
                1,726
                
                
                
                2,624
                
                
                
                (34
                )Lloydminster
                
                
                3,418
                
                
                
                3,622
                
                
                
                (6
                )Other
                
                
                14
                
                
                
                91
                
                
                
                (85
                )26,509
                
                
                
                24,018
                
                
                
                10
 
 (1)
                Provident
      reports equivalent production converting natural gas to oil on a 6:1
      basis.
 (2)
                Represents
      production from June 19, 2007 (date of Capitol Energy Resources Ltd.
      acquisition).
 
 Internal
development activities included 103 net wells drilled for the year ended
December 31, 2007 with a 98 percent success rate. COGP’s drilling activities in
2007 were more focused on crude oil compared to 2006. Provident’s newest core
area, Dixonville had a successful drilling program although there was some
unexpected production tie-in delays from cold weather which resulted in some
additional downtime. Optimization of the production and facilities are ongoing.
Northwest Alberta’s production for 2007 represented a full year of production
from the Rainbow asset acquisition. Northwest Alberta’s successful 2006/2007
winter drilling program resulted in additional production in the first half of
the year that was offset by the impact of unfavorable weather in the fourth
quarter of 2007 causing a unit compressor and pump jack failure. Southeast
Saskatchewan had favorable production results from its optimization activities
and better than expected results from oil well drilling activities. Drilling and
production results from the Triwest assets exceeded internal expectations.
Provident’s other core areas remain active. In southern Alberta, Provident
actively managed production declines through shallow gas well drilling. In
Lloydminster, Provident was successful with its workover activities and
reactivation of oil wells resulting in production increases that were offset by
higher than expected declines.  In West Central Alberta, Provident
continues its strategy of farming out high risk exploration land to generate
cash flow with minimal or no capital outlay.
 
 50
  Revenue
      and royaltiesCOGP
                
                
                
                
                Year
      ended December 31,($
      000s except per boe and mcf data)
                
                2007
                
                
                2006
      %
                
                
                ChangeOilRevenue
                
                $
                202,909
                
                
                $
                169,852
                
                
                
                19Realized
      loss on financial derivative instruments
                
                
                (7,905
                )
                
                
                (3,193
                )
                
                
                148Royalties
                
                
                (39,211
                )
                
                
                (32,567
                )
                
                
                20Net
      revenue
                
                $
                155,793
                
                
                $
                134,092
                
                
                
                16Net
      revenue (per barrel)
                
                $
                43.57
                
                
                $
                41.41
                
                
                
                5Royalties
      as a percentage of revenue
                
                
                19.3
                %
                
                
                19.2
                %Natural
      gasRevenue
                
                $
                216,626
                
                
                $
                200,584
                
                
                
                8Realized
      gain on financial derivative instruments
                
                
                9,633
                
                
                
                7,564
                
                
                
                27Royalties
                
                
                (41,154
                )
                
                
                (42,200
                )
                
                
                (2
                )Net
      revenue
                
                $
                185,105
                
                
                $
                165,948
                
                
                
                12Net
      revenue (per mcf)
                
                $
                5.49
                
                
                $
                5.51
                
                
                
                -Royalties
      as a percentage of revenue
                
                
                19.0
                %
                
                
                21.0
                %Natural
      gas liquidsRevenue
                
                $
                26,451
                
                
                $
                26,545
                
                
                
                -Royalties
                
                
                (6,681
                )
                
                
                (6,458
                )
                
                
                3Net
      revenue
                
                $
                19,770
                
                
                $
                20,087
                
                
                
                (2
                )Net
      revenue (per barrel)
                
                $
                41.16
                
                
                $
                39.28
                
                
                
                5Royalties
      as a percentage of revenue
                
                
                25.3
                %
                
                
                24.3
                %TotalRevenue
                
                $
                445,986
                
                
                $
                396,981
                
                
                
                12Realized
      gain on financial derivative instruments
                
                
                1,728
                
                
                
                4,371
                
                
                
                (60
                )Royalties
                
                
                (87,046
                )
                
                
                (81,225
                )
                
                
                7Net
      revenue
                
                $
                360,668
                
                
                $
                320,127
                
                
                
                13Net
      revenue (per boe)
                
                $
                37.27
                
                
                $
                36.52
                
                
                
                2Royalties
      as a percentage of revenue
                
                
                19.5
                %
                
                
                20.5
                %Note:
      the above revenue, net revenue and net revenue per boe figures are
      presented net of transportation expenses.
 
 For the
year ended December 31, 2007 COGP production revenue was $446.0 million, an
increase of 12 percent from $397.0 million in 2006. The increase in revenue was
a result of the 10 percent increase in production and higher realized crude oil
and natural gas liquids prices. The increase was partially offset by a lower
realized natural gas price.  Royalties as a percentage of revenue have
remained relatively constant at 19.5 percent. The preceding factors, as well as
the $1.7 million realized gain on financial derivative instruments compared to a
$4.4 million gain in 2006, account for net revenue of $360.7 million in 2007, 13
percent higher than the $320.1 million recorded in 2006.
  Net
revenue per boe in 2007 increased two percent to $37.27 from $36.52 in 2006
resulting primarily from higher realized crude oil and natural gas liquids
prices and a higher percentage of production from liquids, partially offset by a
lower realized gas price and a decrease in the realized gain on financial
derivative instruments.
 
 51
  Production
      expensesCOGP
                
                
                
                
                Year
      ended December 31,($
      000s, except per boe data)
                
                2007
                
                
                2006
                
                
                %
      ChangeProduction
      expenses
                
                $
                112,387
                
                
                $
                97,626
                
                
                
                15Production
      expenses (per boe)
                
                $
                11.62
                
                
                $
                11.14
                
                
                
                4
 
 For the
year ended December 31, 2007 production expenses increased 15 percent to $112.4
million from $97.6 million and increased by four percent on a per unit basis to
$11.62 per boe from $11.14 per boe in the prior year. The increase was primarily
due to the increase in production of 10 percent. On a per boe basis, operating
expenses continued to increase in a number of categories including well
servicing, maintenance, fluid hauling, and power and fuel. Cost increases
included increased power costs in July and August 2007 driven by hot weather in
Southern Alberta and West Central Alberta, increased road maintenance costs in
Northwest Alberta due to significant wet weather during the summer months, and
higher than expected ice road maintenance in the winter months. Cost increases
in power and fuel, chemicals and well servicing reflect higher commodity prices
and labour costs.
 
 Operating
      netbackCOGP
                
                
                
                
                Year
      ended December 31,($
      per boe)
                
                2007
                
                
                2006
                
                
                %
      ChangeNetback
      per boeGross
      production revenue
                
                $
                46.09
                
                
                $
                45.29
                
                
                
                2Royalties
                
                
                (9.00
                )
                
                
                (9.27
                )
                
                
                (3
                )Operating
      costs
                
                
                (11.62
                )
                
                
                (11.14
                )
                
                
                4Field
      operating netback
                
                
                25.47
                
                
                
                24.88
                
                
                
                2Realized
      gain on financial derivative instruments
                
                
                0.18
                
                
                
                0.50
                
                
                
                (64
                )Operating
      netback after realized financial derivative instruments
                
                $
                25.65
                
                
                $
                25.38
                
                
                
                1
 
 COGP
operating netbacks have transportation expense netted against gross production
revenue.
  The 2007
field operating netback of $25.47 per boe was two percent above the $24.88 per
boe for the prior year. This reflects COGP’s increased realized crude oil and
natural gas liquids prices and an increase in COGP’s production mix of higher
priced light/medium crude oil to 30 percent in 2007 from 28 percent in 2006 and
a decrease in lower netback heavy oil to seven percent in 2007 from nine percent
in 2006. This was partially offset by lower realized natural gas prices due to
the decrease in benchmark AECO monthly index price and four percent per boe
higher operating costs as explained above. Royalties, which are price sensitive,
decreased by three percent on a boe basis reflecting lower natural gas
prices.  The 2007 operating netbacks after financial derivative
instruments increased by one percent to $25.65 from $25.38 in the prior year due
to the preceding factors as well as the realized gain on financial derivative
instruments of $0.18 per boe compared to $0.50 per boe in the prior
year.
 
 General
and administrative
 
 COGP
                
                
                
                
                Year
      ended December 31,($
      000s, except per boe data)
                
                2007
                
                
                2006
                
                
                %
      ChangeCash
      general and administrative
                
                $
                27,102
                
                
                $
                24,065
                
                
                
                13Non-cash
      unit based compensation
                
                
                3,698
                
                
                
                4,320
                
                
                
                (14
                )$
                30,800
                
                
                $
                28,385
                
                
                
                9Cash
      general and administrative (per boe)
                
                $
                2.80
                
                
                $
                2.75
                
                
                
                2
 
 For the
year ended December 31, 2007, cash general and administrative expenses were
$2.80 per boe, compared to $2.75 per boe in 2006.  The increase in
cash general and administrative expenses reflects additional provisions for
short-term incentive compensation reflecting the performance of the Trust in
relation to established benchmarks.
  52
 Capital
      expendituresCOGP
                
                Year
      ended December 31,($
      000s)
                
                2007
                
                
                2006Capital
      expenditures - by categoryGeological,
      geophysical and land
                
                $
                4,519
                
                
                $
                4,508Drilling
      and recompletions
                
                
                113,425
                
                
                
                56,807Facilities
      and equipment
                
                
                13,378
                
                
                
                6,353Other
      capital
                
                
                14,887
                
                
                
                2,420Total
      additions
                
                $
                146,209
                
                
                $
                70,088Capital
      expenditures - by areaWest
      central Alberta
                
                $
                9,051
                
                
                $
                11,280Southern
      Alberta
                
                
                13,079
                
                
                
                17,619Northwest
      Alberta
                
                
                35,993
                
                
                
                4,883Dixonville
                
                
                43,801
                
                
                
                -Southeast
      Saskatchewan
                
                
                5,069
                
                
                
                1,941Southwest
      Saskatchewan
                
                
                15,196
                
                
                
                25,677Lloydminster
                
                
                9,235
                
                
                
                7,262Office
      and other
                
                
                14,785
                
                
                
                1,426Total
      additions
                
                $
                146,209
                
                
                $
                70,088Property
      acquisitions, net
                
                $
                13,050
                
                
                $
                483,633
 
 In 2007,
Provident’s COGP business unit spent $131.4 million on capital expenditures
before office and other capital costs. Internal development activities included
103 net wells drilled for the year ended December 31, 2007 with a 98 percent
success rate. COGP’s drilling activities in 2007 were more focused on crude oil
compared to 2006. Provident spent $43.8 million in the newest core area,
Dixonville, primarily on drilling and completion activities utilizing three
drilling rigs in the third and fourth quarters of 2007, which resulted in 39.0
net wells drilled.  Provident spent $36.0 million in Northwest
Alberta, primarily on drilling and completion activities and facility work which
included 27.6 net wells drilled, the infrastructure and tie-in activities
associated with the 2006/2007 winter drilling program and preparation work to
start the 2007/2008 winter drilling program. In the Southeast and Southwest
Saskatchewan core areas, $20.3 million was spent which included 20.1 net wells
drilled. At the beginning of the year, the drilling program was primarily
focused on the Southwest Saskatchewan shallow gas drilling program, however as
gas prices declined during the year, the shallow gas drilling program was
reduced significantly and capital was shifted to oil drilling in Dixonville and
to the Triwest assets and facility opportunities in other areas. Southeast
Saskatchewan spending was focused on optimization activities and oil drilling
activity including additional capital for the continuation of the drilling
program on the Triwest assets. In Southern Alberta, $13.1 million was primarily
spent on drilling activity and recompletions which included 9.9 net wells
drilled and on facility upgrades and infrastructure work. In West central
Alberta, $9.1 million was spent largely on non-operated drilling and completion
activities which included 3.0 net wells drilled, facility and infrastructure
work, and recompletion activities. In the Lloydminster core area, $9.2 million
was spent primarily on drilling and recompletion activities which included 3.4
net wells drilled and facility work.
  Additions
to proved plus probable reserves before revisions through internal capital
replaced approximately 44 percent of annual production.
  In 2007,
COGP also spent $13.1 million on property acquisitions primarily on acquiring
additional working interests in Northwest Alberta and Southern
Alberta.
  In
addition, $14.8 million was spent on office and other in 2007, primarily on
office equipment and furniture for the new office space to be occupied in
2008.
 
 53
 
 Depletion,
      depreciation and accretion (DD&A)COGP
                
                
                
                
                Year
      ended December 31,($
      000s, except per boe data)
                
                2007
                
                
                2006
                
                
                %
      ChangeDD&A
                
                $
                256,723
                
                
                $
                168,953
                
                
                
                52DD&A
      (per boe)
                
                $
                26.53
                
                
                $
                19.27
                
                
                
                38
 
 The COGP
DD&A rate of $26.53 per boe increased 38 percent for 2007 compared to $19.27
per boe in 2006. The increase was primarily as a result of the two acquisitions
of Capitol and Triwest in 2007 and the impact of the Rainbow asset acquisition
in the third quarter of 2006 into the full year of 2007. These recent COGP
acquisitions 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. This phenomenon, 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 2007,
DD&A also includes accretion expense associated with asset retirement
obligation of $2.5 million (2006 - $1.9 million).
  As part
of the reconciliation of Provident’s financial statements to United States
generally accepted accounting principles (U.S. GAAP), disclosed in note 19 to
consolidated financial statements, the Trust has reflected additional depletion
in 2007 of $181.6 million (2006 – $382.2 million) and a related future income
tax recovery of $52.2 million (2006 - $114.7 million) as a result of the
application of the U.S. GAAP ceiling test. These changes were not required under
Canadian generally accepted accounting principles.
  54
 USOGP
segment review
 
 The USOGP
business unit incorporates activities from certain Provident subsidiaries
comprising an oil and gas production organization based in Los Angeles,
California.
  In
October 2006, Provident, through its USOGP subsidiaries, completed its initial
public offering (“IPO”) of 6.9 million units at USD $18.50 per unit of BreitBurn
Energy Partners, L.P. (the “MLP”). This master limited partnership (NASDAQ-BBEP)
is a U.S. public, tax flow-through entity similar to Canadian royalty and income
trusts such as Provident. These entities, however, are not affected by the new
Canadian legislation taxing trust distributions commencing in 2011. Selected
producing assets in the Los Angeles basin in California and in Wyoming were
transferred to the MLP.  The previously existing subsidiary
(“BreitBurn”), of which Provident owns approximately 96 percent, continues to
operate assets in the Los Angeles basin at West Pico and other areas, and the
Orcutt field in the Santa Maria basin.
  In May
2007, the MLP completed two oil and gas property acquisitions, one in Florida
for cash consideration of USD $108.1 million and one in California for cash
consideration of USD $92.5 million. The acquisitions were financed by the issue
of 7.0 million common units by the MLP to institutional investors at an average
price of USD $31.58 per unit. As a result of these unit issues, Provident’s
interest in the MLP decreased from approximately 66 percent to approximately 50
percent, resulting in a dilution gain of $98.6 million recorded in the
consolidated statement of operations in the second quarter of 2007.
  On
November 1, 2007, the MLP completed the acquisition of natural gas, oil and
related assets in Michigan, Indiana and Kentucky from Quicksilver Resources Inc.
(“Quicksilver”) in exchange for U.S. $750 million in cash and 21.3 million MLP
units. The cash portion of the acquisition was partially financed through the
issuance of 16.7 million MLP units, at U.S. $27.00 per unit.  As a
result of these unit issues, Provident’s interest in the MLP decreased from
approximately 50 percent to approximately 22 percent, resulting in a dilution
gain of $161.7 million recorded in the consolidated statement of operations in
the fourth quarter of 2007. Provident continues to control and consolidate the
MLP.
  The USOGP
segment 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.
 
 Crude
      oil, natural gas liquids and natural gas pricingUSOGP
                
                
                
                
                Year
      ended December 31,($
      per bbl, except as noted)
                
                2007
                
                
                2006
                
                
                %
      ChangeRealized
      pricing before financial derivative instrumentsLight/medium
      oil and natural gas liquids (Cdn$ per bbl)
                
                $
                65.54
                
                
                $
                63.24
                
                
                
                4Natural
      Gas (Cdn $ per mcf)
                
                $
                7.22
                
                
                $
                6.58
                
                
                
                10
 
 Realized
pricing of light/medium oil and natural gas liquids were four percent higher in
2007 when compared to 2006, equivalent to the increase in WTI, expressed in
Canadian dollars, over the same period.
  Realized
natural gas pricing before financial derivative instruments was up 10 percent in
2007 when compared to 2006. The increase was primarily associated with the
increase in Henry Hub pricing. In addition, the newly acquired Michigan
properties have favorable natural gas supply/demand characteristics as the state
has been importing an increasing percentage of its natural gas.
 
 ProductionYear
      ended December 31,USOGP
                
                2007
                
                
                2006
                
                
                %
      ChangeDaily
      production - by productCrude
      oil - Light/Medium (bpd)
                
                
                9,557
                
                
                
                7,299
                
                
                
                31Natural
      gas liquids (bpd)
                
                
                105
                
                
                
                18
                
                
                
                483Natural
      gas (mcfd)
                
                
                14,773
                
                
                
                2,422
                
                
                
                510Oil
      equivalent (boed) (1)
                
                
                12,124
                
                
                
                7,721
                
                
                
                57(1)Provident reports equivalent production converting natural gas to
      oil on a 6:1 basis.
 55
 Year
      ended December 31,USOGP
                
                2007
                
                
                2006
                
                
                %
      ChangeDaily
      Production - by area (boed) (1)Los
      Angeles
                
                
                4,203
                
                
                
                3,901
                
                
                
                8Santa
      Maria - Orcutt
                
                
                1,555
                
                
                
                1,491
                
                
                
                4Wyoming
                
                
                2,554
                
                
                
                2,329
                
                
                
                10Texas
                
                
                349
                
                
                
                -
                
                
                
                -Florida
                
                
                1,099
                
                
                
                -
                
                
                
                -Michigan/Indiana/Kentucky
                
                
                2,364
                
                
                
                -
                
                
                
                -12,124
                
                
                
                7,721
                
                
                
                57(1)Provident reports equivalent production converting natural gas to
      oil on a 6:1 basis.
 
 USOGP
production increased 4,403 boe per day or 57 percent in 2007 when compared to
2006. The increase is primarily attributable to acquisitions made by USOGP in
2007, which included fields in Los Angeles, Florida, Texas, Michigan, Indiana
and Kentucky.  Production from the MLP for the year ended December 31,
2007 was 9,518 boed, while production from BreitBurn was 2,606
boed.
 
 Revenue
and royalties
 
 The
following table outlines USOGP revenue and royalties by product
line.  The table excludes revenues earned from operating certain
properties ($1.3 million in the year ended December 31, 2007 (2006 - $1.0
million)) on behalf of third parties. The table also excludes revenue from the
sale of inventory acquired as part of the Florida acquisition in May 2007,
amounting to $12.8 million in the year ended December 31, 2007.
 
 USOGP
                
                
                
                
                Year
      ended December 31,($
      000s, except per boe and mcf amounts)
                
                2007
                
                
                2006
                
                
                %
      ChangeOil
      and natural gas liquidsRevenue
                
                $
                222,263
                
                
                $
                169,322
                
                
                
                31Realized
      loss on financial derivative instruments
                
                
                (7,959
                )
                
                
                (2,505
                )
                
                
                218Royalties
                
                
                (25,294
                )
                
                
                (16,554
                )
                
                
                53Net
      revenue
                
                $
                189,010
                
                
                $
                150,263
                
                
                
                26Net
      revenue (per bbl)
                
                $
                55.73
                
                
                $
                56.26
                
                
                
                (1
                )Royalties
      as a percentage of revenue
                
                
                11.4
                %
                
                
                9.8
                %Natural
      gasRevenue
                
                $
                38,930
                
                
                $
                5,820
                
                
                
                569Royalties
                
                
                (6,360
                )
                
                
                (761
                )
                
                
                736Net
      revenue
                
                $
                32,570
                
                
                $
                5,059
                
                
                
                544Net
      revenue (per mcf)
                
                $
                6.04
                
                
                $
                5.72
                
                
                
                6Royalties
      as a percentage of revenue
                
                
                16.3
                %
                
                
                13.1
                %TotalRevenue
                
                $
                261,193
                
                
                $
                175,142
                
                
                
                49Realized
      loss on financial derivative instruments
                
                
                (7,959
                )
                
                
                (2,505
                )
                
                
                218Royalties
                
                
                (31,654
                )
                
                
                (17,315
                )
                
                
                83Net
      revenue
                
                $
                221,580
                
                
                $
                155,322
                
                
                
                43Net
      revenue (per boe)
                
                $
                51.65
                
                
                $
                55.12
                
                
                
                (6
                )Royalties
      as a percentage of revenue
                
                
                12.1
                %
                
                
                9.9
                %
 
 Note: the
above revenue, net revenue and net revenue per boe figures are presented net of
transportation expenses. Per boe figures are calculated using sales volumes,
which differ from production volumes due to changes in inventory levels at the
Florida properties, acquired in the second quarter of 2007.
  For the
year ended December 31, 2007 revenue was 49 percent higher than the year ended
December 31, 2006 primarily due to increases in sales volumes from the
acquisitions. Royalties as a percentage of revenue have increased as royalties
at the Michigan, Wyoming, Texas and Florida properties are higher than those
incurred at the Southern California operations. Net revenue for the year ended
December 31, 2007 was 43 percent higher than the year ended December 31, 2006
due to all the
 
 56
  
 acquisitions
in 2007 and the higher crude oil and natural gas prices. These increases were
partially offset by higher realized losses on financial derivative instruments
in 2007 compared to 2006.
 
 Production
      expensesUSOGP
                
                
                
                
                Year
      ended December 31,($
      000s, except per boe amounts)
                
                2007
                
                
                2006
                
                
                %
      ChangeProduction
      expenses
                
                $
                81,699
                
                
                $
                52,008
                
                
                
                57Production
      expenses (per boe)
                
                $
                19.04
                
                
                $
                18.45
                
                
                
                3
 
 Note: Per
boe figures are cal cul ated using sales volumes, which differ from production
volumes due to changes in inventory level s at the Florida properties, acquired
in the second quarter of 2007.
  
 Production
expenses increased 57 percent to $81.7 million in 2007 compared to $52.0 million
in 2006. Production expenses per boe have increased three percent to $19.04 in
2007 from $18.45 in 2006. This change reflects both the increase in utilities
and other costs and services driven by the high commodity price environment as
well as higher operating cost crude oil wells that were returned to production
to take advantage of continuing strong crude oil prices. These increases were
largely offset by lower production costs per boe from the newly acquired
Michigan properties.
 
 Operating
      netbackUSOGP
                
                
                
                
                Year
      ended December 31,($
      per boe)
                
                2007
                
                
                2006
                
                
                %
      ChangeUSOGP
      oil equivalent netback per boeGross
      production revenue
                
                $
                60.88
                
                
                $
                62.15
                
                
                
                (2
                )Royalties
                
                
                (7.38
                )
                
                
                (6.14
                )
                
                
                20Operating
      costs
                
                
                (19.04
                )
                
                
                (18.45
                )
                
                
                3Field
      operating netback
                
                $
                34.46
                
                
                $
                37.56
                
                
                
                (8
                )Realized
      loss on financial derivative instruments
                
                
                (1.85
                )
                
                
                (0.89
                )
                
                
                108Operating
      netback after realized financial derivative instruments
                
                $
                32.61
                
                
                $
                36.67
                
                
                
                (11
                )
 
 Note: Per
boe figures are calculated using sales volumes, which differ from production
volumes due to changes in inventory levels at the Florida properties, acquired
in the second quarter of 2007.
  
 USOGP
operating netbacks remained strong throughout 2007 due to high commodity prices,
partially offset by higher realized losses on financial derivative instruments
when compared to 2006 and increased production costs and royalties.
 
 General
      and administrativeUSOGP
                
                
                
                
                Year
      ended December 31,($
      000s, except per boe amounts)
                
                2007
                
                
                2006
                
                
                %
      ChangeCash
      general and administrative
                
                $
                45,188
                
                
                $
                26,519
                
                
                
                70Non-cash
      unit based compensation
                
                
                5,950
                
                
                
                12,476
                
                
                
                (52
                )$
                51,138
                
                
                $
                38,995
                
                
                
                31Cash
      general and administrative (per boe)
                
                $
                10.21
                
                
                $
                9.41
                
                
                
                9
 
 For the
year ended December 31, 2007, cash general and administrative expenses were
$45.2 million (2006 – $26.5 million). 2007 cash general and administrative
expense includes $13.9 million or $3.14 per boe (2006 - $5.0 million or $1.75
per boe) related to payments associated with unit based compensation. The
expense was accrued in 2006 as non-cash unit based compensation, consequently
there is an offsetting reduction in non-cash unit based compensation in 2007,
when the payments were made. Excluding these payments, cash general and
administrative expenses were $31.3 million or $7.07 per boe for the year ended
December 31, 2007 compared to $21.5 million or $7.63 per boe for the same period
in 2006. The increase was due to increased costs associated with regulatory
compliance as well as increased staffing levels required for the rapidly growing
public MLP.
  Non-cash
unit based compensation for the year ended December 31, 2007 was $6.0 million
(2006 - $12.5 million expense). Year-to-date 2007 cash payments related to unit
based compensation were $13.9 million compared to $5.0 million in 2006. Payment
of unit based compensation is recorded as cash general and administrative
expense with an offsetting reduction in
 
 57
 
 non-cash
unit based compensation. Excluding this payment, non-cash unit based
compensation was $19.9 million for the year ended December 31, 2007 (2006 -
$17.5 million). The increase in expense in 2007 reflects higher staffing levels
due to the acquisitions as well as strong MLP performance in 2007.
 
 Capital
      expendituresUSOGP
                
                Year
      ended December 31,($
      000s)
                
                2007
                
                
                2006Capital
      expenditures - by categoryGeological,
      geophysical and land
                
                $
                1,715
                
                
                $
                104Drilling
      and recompletions
                
                
                42,196
                
                
                
                30,943Facilities
      and equipment
                
                
                18,691
                
                
                
                18,486Other
      capital
                
                
                6,407
                
                
                
                4,804Total
      additions
                
                $
                69,009
                
                
                $
                54,337Property
      acquisitions, net
                
                $
                1,015,803
                
                
                $
                (2,008
                )
 
 USOGP
capital expenditures for the year ended December 31, 2007 totaled $69.0 million.
Of this total, $58.8 million related to drilling, optimization and facility
upgrades at Orcutt, Wyoming, Santa Fe Springs and the newly acquired Michigan
properties.
  In 2007,
USOGP completed property acquisitions of $1,015.8 million. $115.6 million
represents the Florida acquisition and $98.9 million was spent on an acquisition
in California. An additional $37.6 million was directed at acquiring additional
wells in Texas, Los Angeles and Wyoming. $763.7 million represents the cash
portion of the USOGP natural gas asset acquisition.
 
 Depletion,
      depreciation and accretion (DD&A)USOGP
                
                
                
                
                Year
      ended December 31,($
      000s, except per boe amounts)
                
                2007
                
                
                2006
                
                
                %
      ChangeDD&A
                
                $
                50,253
                
                
                $
                31,058
                
                
                
                62DD&A
      (per boe)
                
                $
                11.36
                
                
                $
                11.02
                
                
                
                3
 
 The
USOGP’s DD&A rate is low due to the long-lived nature of the assets. On a
per boe basis the DD&A rate was up $11.36 or three percent in 2007 when
compared to 2006. The change reflects higher depletion costs related to the
recent producing property acquisitions.
 
 Recent
developments
 
 USOGP
continues to progress on its acquisition integration. The MLP expects to
complete its system integration relating to the USOGP natural gas asset
acquisition in the second quarter of 2008.
 
 58
  
 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,
Provident holds 18.3 percent ownership of a 300,000 barrel Superior Storage
staging facility and 18.3 percent ownership of the 6,600 bpd Superior
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 350 rail cars.
 
 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.
  • 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 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 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. Provident
also has long-term shipping rights on the Pembina Peace Pipeline that extends
the product delivery transportation network through to the Redwater
fractionation facility.
 
 • A rail car fleet
of approximately 485 rail cars.
  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
 59
 50
percent ownership in the Kerrobert Pipeline which transports NGLs from Empress
to Kerrobert for injection into the Enbridge pipeline for delivery to
Sarnia.  Further, 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 facility, a significant portion of the available propane plus 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.
 
 Also,
      see commitments disclosure in note 15 to the consolidated financial
      statements.2007
      Midstream business unit results can be summarized as
    follows:Year
      ended December 31,($
      000s)
                
                2007
                
                
                2006
                
                
                %
      ChangeEmpress
      East Margin
                
                $
                183,565
                
                
                $
                133,549
                
                
                
                37Redwater
      West Margin
                
                
                94,600
                
                
                
                75,686
                
                
                
                25Commercial
      Services Margin
                
                
                54,649
                
                
                
                46,695
                
                
                
                17Gross
      operating margin
                
                
                332,814
                
                
                
                255,930
                
                
                
                30Realized
      loss on financial derivative instruments
                
                
                (74,474
                )
                
                
                (15,406
                )
                
                
                383Cash
      general and administrative expenses
                
                
                (28,669
                )
                
                
                (23,621
                )
                
                
                21Foreign
      exchange (loss) gain and other
                
                
                (3,996
                )
                
                
                2,728
                
                
                
                -Midstream
      EBITDA
                
                $
                225,675
                
                
                $
                219,631
                
                
                
                3Note:
      Certain comparative amounts have been reclassified to conform with the
      current year presentation.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
prices and crude oil prices which can change prices received and margins
realized for Midstream products separate from frac spread ratio
changes.  The 2007 margin was $183.6 million compared to $133.5
million in 2006.  The increase reflects approximately 10 percent
higher propane-plus prices and lower transportation related costs, partially
offset by five percent lower propane-plus sales volumes. Also, the 2006 gross
operating margin includes the impact of a $5.2 million repayment incurred under
the fractionation spread support program.
  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. In 2007, the margin for
this business line was $94.6 million (2006 - $75.7 million). The increase in
margin was primarily due to an increase in propane-plus sales volumes and a 10
percent increase in propane-plus prices.
  60
 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 2007, the margin for
this business line was $54.6 million (2006 - $46.7 million). The increase in the
margin is due to increased revenue associated with the condensate
loading/offloading facility at Redwater which operated for a full year in
2007.
 
 Operations
– Midstream NGL sales volumes
  Midstream
sold 120,785 bpd in 2007, up five percent when compared with 2006.
  Earnings before interest, taxes,
depletion, depreciation, accretion, and other non-cash items
(“EBITDA”)and funds flow from
operations
  For 2007,
EBITDA increased $6.0 million or three percent from $219.6 million in
2006.  A $76.9 million increase in gross operating margin as described
above was tempered by a $59.1 million increase in realized losses on financial
derivative instruments and higher cash general and administrative and other
costs. The increased cost associated with the financial derivative instruments
in 2007 is offset by the realized product margin during the year. Funds flow
from operations for 2007 was $178.4 million, a decrease of $6.0 million below
the $184.4 million in 2006. The decrease in funds flow from operations reflects
the higher EBITDA offset by higher interest costs due to increased corporate
long-term debt balances, and higher taxes.
  Cash
general and administrative expenses and other were $28.7 million for 2007 (2006
- $23.6 million) reflecting additional provisions for short-term incentive
compensation due to the performance of the Trust in relation to established
benchmarks.
  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 funds flow from operations or operating profits for the
period nor should it be viewed as an alternative to funds 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”).
 
 Fractionation
spread support program
 
 As part
of the December 2005 Midstream NGL Acquisition, the vendor agreed to provide a
near-term fractionation spread support program. The program provides Provident
with up to $75 million of support in 2006 and up to October 31, 2007 if the
fractionation spread ratio is below historic levels. This program was intended
to ensure that Provident achieves the long-term average fractionation spread
ratio that the NGL business has attained historically. There was no activity
under this agreement in 2007 or the last three quarters of 2006. In the first
quarter of 2006, there was a repayment of $5.2 million that was received in the
fourth quarter of 2005. The program has now expired.
 
 Capital
expenditures
 
 Midstream
capital expenditures in 2007 totaled $31.9 million. In 2007, $5.3 million was
spent on a new condensate offloading and terminalling facility, expansion to the
recently completed truck loading facilities, and continued development of cavern
storage. In addition, $13.9 million was added to capitalized line-fill, $4.5
million was spent on sustaining capital requirements and $8.2 million was spent
primarily on office furniture and equipment for the new office space to be
occupied in 2008.
 
 61
 Foreign
ownership
 
 Based on
information received from our transfer agent and financial intermediaries in
January 2008, 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 policies
 
 Provident’s
accounting policies are described in note 2 to the consolidated financial
statements. Certain accounting policies are identified as critical accounting
policies because they form an integral part of Provident’s financial position.
They also 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.
 
 Details
of Provident’s critical accounting policies are as follows:
  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.
  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., an independent engineering firm, to evaluate
Provident’s Canadian reserves. For Provident’s U.S. based assets, management
utilizes Netherland, Sewell & Associates, Inc., and Schlumberger Data &
Consulting Services, independent engineering firms, to evaluate
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.
 
 62
  
 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
  Financial
instruments and comprehensive income
  Effective
January 1, 2007, Provident adopted the requirements of the Canadian Institute of
Chartered Accountants (“CICA”) related to the new financial instruments
accounting framework, which encompasses the following new CICA Handbook
sections:  3855 Financial Instruments – Recognition and Measurement,
1530 Comprehensive income, and 3861 Financial Instruments – Disclosure and
Presentation. The CICA Handbook section 3865 Hedges is effective January 1,
2007, however, Provident has elected not to apply hedge accounting, consistent
with prior periods.
  These new
Handbook sections provide comprehensive requirements for the recognition and
measurement of financial instruments, and introduce a new component of equity
referred to as accumulated other comprehensive income (“AOCI”). In accordance
with the transitional provisions of all of the new sections, the comparative
interim consolidated financial statements have not been restated, except that
the “Cumulative translation adjustment” has been reclassified to “Accumulated
other comprehensive income”.
  Under
these new standards, 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 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
long-term debt) are measured at amortized cost using the effective interest rate
method.  Transaction costs are included with the associated financial
instrument and amortized accordingly.
  Several
adjustments in the Trust’s consolidated financial statements were required upon
transition to the new financial instruments framework, which were the
following:
 
 Long-term
debt and deferred financing charges
 
 Prior to
the adoption of the new standards, financing charges related to long-term debt
were included in “Deferred financing charges” on the Trust’s Consolidated
Balance Sheet, and recognized in net income over the life of the
debt.
  Under the
transitional provisions of Handbook section 3855 Financial Instruments –
Recognition and Measurement, the Trust’s long-term debt – revolving credit
facilities is now recorded at amortized cost using the effective interest rate
method.  The related financing charges have been included in the cost
of the long-term debt.  As a result of these changes, “Deferred
financing charges” of $3.0 million, and prepaid interest of $8.5 million, which
were previously recorded as assets of the Trust, were reclassified to “Long-term
debt – revolving credit facilities” on the Consolidated Balance Sheet. The
accounting treatment for “Long-term debt – convertible debentures” is the same
as in prior periods, except that related deferred financing charges are now
included in the carrying amount.  Deferred financing charges of $9.4
million were reclassified to “Long-term debt – convertible debentures” on the
Consolidated Balance Sheet.
 
 63
 
 Statement
of comprehensive income
 
 The
consolidated financial statements now include a new Consolidated Statement of
Comprehensive Income and Accumulated Other Comprehensive
Income.  Other comprehensive income includes foreign currency
translation adjustments relating to self-sustaining foreign operations and
unrealized gains and losses on available-for-sale investments, net of the
related future income tax on those items.
 
 Equity
 
 In 2005,
the CICA issued Section 3251 “Equity”. This Section replaces Section 3250
“Surplus” and Section requires an entity to present separately each of the
changes in equity during the period, including comprehensive income, as well as
components of equity at the end of the period. This Section applies to interim
and annual financial statements relating to fiscal years beginning on or after
October 1, 2006. The application of this standard has not had a material impact
on the Trust’s financial statements.
 
 Accounting
changes
 
 In 2006,
the CICA released Section 1506 “Accounting Changes” which establishes criteria
for changing accounting policies. Under the new section, voluntary changes in
accounting policy are only made if they result in the financial statements
providing reliable and more relevant information. Changes in accounting policy
are applied retroactively unless it is impracticable to do so or the change in
accounting policy is made on initial application of a primary source of GAAP,
and that primary source of GAAP has specific transitional provisions. All
material prior period errors are to be corrected retroactively. This section is
effective for interim and annual financial statements for fiscal years beginning
on or after January 1, 2007. The application of this standard has not had a
material impact on the Trust’s financial statements.
  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
risk and the ability to finance future growth; a
  • nd 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:
 
 • fluctuations in
commodity price, exchange rates and interest rates;
  • g overnment
and regulatory risk in respect of royalty and income tax regimes;
  • 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;
  64
  
 • 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;
  • 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.
 
 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, 2007 on both the
Toronto Stock Exchange and the New York Stock Exchange:
 
 Q1
                
                
                
                Q2
                
                
                
                Q3
                
                
                
                Q4TSE
      – PVE.UN (Cdn$)High
                
                $
                13.02
                
                
                $
                13.57
                
                
                $
                12.99
                
                
                $
                12.70Low
                
                $
                11.63
                
                
                $
                12.38
                
                
                $
                11.02
                
                
                $
                9.60Close
                
                $
                12.50
                
                
                $
                12.52
                
                
                $
                12.64
                
                
                $
                9.98Volume
      (000s)
                
                
                16,531
                
                
                
                29,522
                
                
                
                35,898
                
                
                
                36,302NYSE
      – PVX (US$)High
                
                $
                11.24
                
                
                $
                12.20
                
                
                $
                12.73
                
                
                $
                13.55Low
                
                $
                9.97
                
                
                $
                10.76
                
                
                $
                10.00
                
                
                $
                9.65Close
                
                $
                10.83
                
                
                $
                11.89
                
                
                $
                12.69
                
                
                $
                10.00Volume
      (000s)
                
                
                54,407
                
                
                
                61,559
                
                
                
                57,885
                
                
                
                75,057
 
 65
 
 Forward-looking
Statements
 
 This
MD&A contains forward-looking information or forward-looking statements
under applicable securities legislation. These statements relate to future
events or the Trust's future performance.  Such forward-looking
statements or information are 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 statements. In some
cases, forward-looking statements 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 statements, as they involve the implied assessment,
based on certain estimates and assumptions, that the resources and reserves
described can be profitably produced in the future.  Forward looking
statements or information in this MD&A include, but are 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 statements or information are 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
statements or information.  In addition, this MD&A may contain
forward-looking statements attributed to third party industry
sources.  Undue reliance should not be placed on forward-looking
statements or 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 statements will not occur. Forward-looking statements in this
MD&A include, but are 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;
 • 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 a consistent level of monthly cash distributions;
 • the impact of
Canadian governmental regulation on the Trust;
 • t he
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 hedging;
 • 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
statements 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 statements. 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 or
forward-looking statements contained in this MD&A include, but are not
limited to:
 
 • general economic
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;
  66
 • 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 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 forwarding looking statements and
forward looking information contained in this MD&A, the Trust has made
assumptions regarding, among other things:
 
 • 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; and
 • 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. The forward-looking statements or information
contained in this MD&A are made as of the date hereof and the Trust
undertakes no obligation to update publicly or revise any forward-looking
statements or information, whether as a result of new information, future events
or otherwise unless required by applicable securities laws. The forward looking
statements or information contained in this MD&A are 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)
                
                2007
                
                
                2006
                
                
                2005Revenue
      (net of royalties and financial derivative instruments)
                
                $
                2,167,276
                
                
                $
                2,187,253
                
                
                $
                1,360,274Net
      income
                
                
                30,434
                
                
                
                140,920
                
                
                
                96,926Net
      income per unit - basic and diluted
                
                
                0.13
                
                
                
                0.72
                
                
                
                0.61Total
      assets
                
                
                5,758,792
                
                
                
                3,370,919
                
                
                
                2,792,270Long-term
      financial liabilities (1)
                
                
                1,863,512
                
                
                
                1,098,040
                
                
                
                930,756Declared
      distributions per unit.
                
                $
                1.44
                
                
                $
                1.44
                
                
                $
                1.44(1)Includes l ong-term debt, asset retirement obligation, long-term
      financial derivative instruments and other long-term
      liabilities.
 
 67
 Quarterly
      tableSegmented
      information by quarter($
      000s except for per unit and operating amounts)
                
                
                
                
                
                
                
                2007First
                
                
                Second
                
                
                Third
                
                
                Fourth
                
                
                Year-to-Quarter
      (1)
                
                
                Quarter
      (1)
                
                
                Quarter
                
                
                Quarter
                
                
                DateFinancial
      - consolidatedRevenue
                
                $
                587,675
                
                
                $
                504,468
                
                
                $
                533,249
                
                
                $
                541,884
                
                
                $
                2,167,276Funds
      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 productionCash
      revenue
                
                $
                125,777
                
                
                $
                139,453
                
                
                $
                155,541
                
                
                $
                186,891
                
                
                $
                607,662Earnings
      before interest, DD&A, taxes
                
                $
                54,736
                
                
                $
                75,783
                
                
                $
                82,523
                
                
                $
                106,379
                
                
                $
                319,421and
      other non-cash itemsFunds
      flow from operations
                
                $
                47,636
                
                
                $
                68,934
                
                
                $
                72,799
                
                
                $
                100,454
                
                
                $
                289,823Net
      (loss) income
                
                $
                (8,745
                )
                
                $
                95,992
                
                
                $
                (26,375
                )
                
                $
                130,582
                
                
                $
                191,454Midstream
      services and marketingCash
      revenue
                
                $
                453,272
                
                
                $
                397,713
                
                
                $
                433,950
                
                
                $
                598,963
                
                
                $
                1,883,898Earnings
      before interest, DD&A, taxes
                
                $
                52,853
                
                
                $
                35,974
                
                
                $
                47,425
                
                
                $
                89,423
                
                
                $
                225,675and
      other non-cash itemsFunds
      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 productionLight/medium
      oil (bpd)
                
                
                14,071
                
                
                
                15,557
                
                
                
                19,289
                
                
                
                20,721
                
                
                
                17,433Heavy
      oil (bpd)
                
                
                1,669
                
                
                
                1,918
                
                
                
                2,324
                
                
                
                1,769
                
                
                
                1,921Natural
      gas liquids (bpd)
                
                
                1,444
                
                
                
                1,344
                
                
                
                1,281
                
                
                
                1,612
                
                
                
                1,421Natural
      gas (mcfd)
                
                
                91,432
                
                
                
                96,449
                
                
                
                95,588
                
                
                
                144,678
                
                
                
                107,151Oil
      equivalent (boed)
                
                
                32,423
                
                
                
                34,893
                
                
                
                38,825
                
                
                
                48,215
                
                
                
                38,633Average
      selling price net of transportation expenseLight/medium
      oil per bbl
                
                $
                57.21
                
                
                $
                59.44
                
                
                $
                64.59
                
                
                $
                69.70
                
                
                $
                63.48(before
      realized financial derivative instruments)Light/medium
      oil per bbl
                
                $
                59.93
                
                
                $
                59.39
                
                
                $
                61.37
                
                
                $
                62.34
                
                
                $
                60.93(including
      realized financial derivative instruments)Heavy
      oil per bbl
                
                $
                34.69
                
                
                $
                42.32
                
                
                $
                45.34
                
                
                $
                43.36
                
                
                $
                41.85(before
      realized financial derivative instruments)Heavy
      oil per bbl
                
                $
                34.69
                
                
                $
                42.32
                
                
                $
                45.34
                
                
                $
                43.36
                
                
                $
                41.85(including
      realized financial derivative instruments)Natural
      gas liquids per barrel
                
                $
                48.86
                
                
                $
                52.56
                
                
                $
                55.22
                
                
                $
                51.39
                
                
                $
                51.90Natural
      gas per mcf
                
                $
                7.48
                
                
                $
                7.25
                
                
                $
                4.95
                
                
                $
                6.53
                
                
                $
                6.53(before
      realized financial derivative instruments)Natural
      gas per mcf
                
                $
                7.37
                
                
                $
                7.18
                
                
                $
                5.62
                
                
                $
                6.92
                
                
                $
                6.78(including
      realized financial derivative instruments)MidstreamMidstream
      NGL sales volumes (bpd)
                
                
                125,033
                
                
                
                109,713
                
                
                
                112,386
                
                
                
                135,981
                
                
                
                120,785(1)Restated - see note 3 to third quarter 2007 interim consolidated
      financial statements.
 
 68
  
 Quarterly
      tableSegmented
      information by quarter($
      000s except for per unit and operating amounts)
                
                
                
                
                
                
                
                2006First
                
                
                Second
                
                
                Third
                
                
                Fourth
                
                
                AnnualQuarter
                
                
                Quarter
                
                
                Quarter
                
                
                Quarter
                
                
                TotalFinancial
      - consolidatedRevenue
                
                $
                553,706
                
                
                $
                424,439
                
                
                $
                661,022
                
                
                $
                548,086
                
                
                $
                2,187,253Funds
      flow from operations
                
                $
                78,906
                
                
                $
                110,990
                
                
                $
                120,089
                
                
                $
                122,679
                
                
                $
                432,664Net
      income (loss)
                
                $
                24,200
                
                
                $
                21,371
                
                
                $
                120,850
                
                
                $
                (25,501
                )
                
                $
                140,920Net
      income (loss) per unit - basic
                
                $
                0.13
                
                
                $
                0.11
                
                
                $
                0.61
                
                
                $
                (0.12
                )
                
                $
                0.72Net
      income (loss) per unit - diluted
                
                $
                0.13
                
                
                $
                0.11
                
                
                $
                0.58
                
                
                $
                (0.12
                )
                
                $
                0.72Unitholder
      distributions
                
                $
                68,350
                
                
                $
                68,572
                
                
                $
                70,970
                
                
                $
                75,573
                
                
                $
                283,465Distributions
      per unit
                
                $
                0.36
                
                
                $
                0.36
                
                
                $
                0.36
                
                
                $
                0.36
                
                
                $
                1.44Oil
      and gas productionCash
      revenue
                
                $
                114,020
                
                
                $
                125,744
                
                
                $
                116,682
                
                
                $
                125,135
                
                
                $
                481,581Earnings
      before interest, DD&A, taxes
                
                $
                64,313
                
                
                $
                77,698
                
                
                $
                67,750
                
                
                $
                66,497
                
                
                $
                276,258and
      other non-cash itemsFunds
      flow from operations
                
                $
                52,813
                
                
                $
                71,867
                
                
                $
                61,471
                
                
                $
                62,147
                
                
                $
                248,298Net
      income (loss)
                
                $
                36,484
                
                
                $
                25,980
                
                
                $
                38,117
                
                
                $
                (14,530
                )
                
                $
                86,051Midstream
      services and marketingCash
      revenue
                
                $
                474,515
                
                
                $
                367,624
                
                
                $
                459,603
                
                
                $
                447,244
                
                
                $
                1,748,986Earnings
      before interest, DD&A, taxes
                
                $
                32,813
                
                
                $
                46,438
                
                
                $
                65,958
                
                
                $
                74,422
                
                
                $
                219,631and
      other non-cash itemsFunds
      flow from operations
                
                $
                26,093
                
                
                $
                39,123
                
                
                $
                58,618
                
                
                $
                60,532
                
                
                $
                184,366Net
      income (loss)
                
                $
                (12,284
                )
                
                $
                (4,609
                )
                
                $
                82,733
                
                
                $
                (10,971
                )
                
                $
                54,869OperatingOil
      and gas productionLight/medium
      oil (bpd)
                
                
                14,541
                
                
                
                13,923
                
                
                
                13,955
                
                
                
                13,899
                
                
                
                14,114Heavy
      oil (bpd)
                
                
                2,506
                
                
                
                2,011
                
                
                
                2,004
                
                
                
                1,838
                
                
                
                2,057Natural
      gas liquids (bpd)
                
                
                1,527
                
                
                
                1,475
                
                
                
                1,326
                
                
                
                1,345
                
                
                
                1,419Natural
      gas (mcfd)
                
                
                78,274
                
                
                
                80,084
                
                
                
                80,991
                
                
                
                100,029
                
                
                
                84,891Oil
      equivalent (boed)
                
                
                31,620
                
                
                
                30,756
                
                
                
                30,784
                
                
                
                33,753
                
                
                
                31,739Average
      selling price net of transportation expenseLight/medium
      oil per bbl
                
                $
                54.80
                
                
                $
                69.76
                
                
                $
                62.95
                
                
                $
                54.59
                
                
                $
                60.32(before
      realized financial derivative instruments)Light/medium
      oil per bbl
                
                $
                53.40
                
                
                $
                68.00
                
                
                $
                60.72
                
                
                $
                55.56
                
                
                $
                59.22(including
      realized financial derivative instruments)Heavy
      oil per bbl
                
                $
                22.87
                
                
                $
                50.42
                
                
                $
                48.15
                
                
                $
                25.82
                
                
                $
                36.80(before
      realized financial derivative instruments)Heavy
      oil per bbl
                
                $
                22.82
                
                
                $
                50.42
                
                
                $
                48.15
                
                
                $
                25.82
                
                
                $
                36.78(including
      realized financial derivative instruments)Natural
      gas liquids per barrel
                
                $
                53.91
                
                
                $
                54.20
                
                
                $
                52.03
                
                
                $
                47.49
                
                
                $
                51.98Natural
      gas per mcf
                
                $
                8.00
                
                
                $
                6.10
                
                
                $
                5.88
                
                
                $
                6.71
                
                
                $
                6.66(before
      realized financial derivative instruments)Natural
      gas per mcf
                
                $
                7.85
                
                
                $
                6.41
                
                
                $
                6.24
                
                
                $
                7.12
                
                
                $
                6.91(including
      realized financial derivative instruments)MidstreamMidstream
      NGL sales volumes (bpd)
                
                
                130,735
                
                
                
                100,284
                
                
                
                114,839
                
                
                
                115,727
                
                
                
                115,354
 
 69
  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, 2007, our internal control over financial reporting was
effective.
  Management
excluded from its assessment of the effectiveness of the Trust’s internal
control over financial reporting certain assets acquired from Quicksilver
Resources, Inc. because they were acquired by a subsidiary of the Trust in a
purchase business combination during 2007 (as further described in note 4 of the
Trust’s consolidated financial statements). Such total assets and total revenues
represent approximately 26 percent and less than one percent respectively, of
the related consolidated financial statement amounts as of and for the year
ended December 31, 2007.
  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, 2007, has been audited by PricewaterhouseCoopers LLP, independent
auditors, as stated in their report which appears herein.
 
 graphic
                graphic“signed”
                “signed”Thomas
      W. Buchanan
                Mark
      N. WalkerChief
      Executive Officer
                Chief
      Financial OfficerCalgary,
      AlbertaMarch
      18, 2008
  70
  
 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.
 
 graphic
                graphic“signed”
                “signed”Thomas
      W. Buchanan
                Mark
      N. WalkerChief
      Executive Officer
                Chief
      Financial OfficerCalgary,
      AlbertaMarch
      18, 2008
 
 71
 
 
  
 GRAPHIC
 
 GRAPHIC
 
  
 PROVIDENT
      ENERGY TRUSTCONSOLIDATED
      BALAN CE SHEETSCanadian
      dollars (000s)
  As
      at
                
                
                As
      atDecember
      31,
                
                
                Decem
      ber 31,2007
                
                
                2006AssetsCur
      rent assetsCash
      and cash equival ents
                
                $
                6,820
                
                
                $
                10,302Account
      s r eceivable
                
                
                417,562
                
                
                
                270,135Petroleum
      pr oduct inventor y
                
                
                90,274
                
                
                
                85,868Prepaid
      expenses and other cur r ent assets
                
                
                9,018
                
                
                
                16,381Financial
      der ivative instr um ents (note 13)
                
                
                2,289
                
                
                
                12,909525,963
                
                
                
                395,595Invest
      m ent s
                
                
                21,154
                
                
                
                4,320Defer
      r ed f inancing char ges
                
                
                -
                
                
                
                12,351Long-
      term f
      inancial der ivat ive inst r um ents (not e 13)
                
                
                -
                
                
                
                171Pr
      oper ty, plant and equipm ent (note 5)
                
                
                4,518,820
                
                
                
                2,333,537Intangible
      assets (note 6)
                
                
                175,556
                
                
                
                193,592Goodwill
      (note 4)
                
                
                517,299
                
                
                
                431,353$
                5,758,792
                
                
                $
                3,370,919LiabilitiesCur
      rent liabilitiesAccount
      s payable and accr ued liabilit ies
                
                $
                424,468
                
                
                $
                295,003Cash
      dist r ibutions payable
                
                
                25,100
                
                
                
                21,506Distr
      ibutions payable to non- contr olling int er ests
                
                
                -
                
                
                
                677Curr
      ent por tion of convert ible debent ures (note 7)
                
                
                19,198
                
                
                
                -Financial
      der ivative instr um ents (note 13)
                
                
                167,713
                
                
                
                22,602636,479
                
                
                
                339,788Long-
      term debt
      - revolvingterm
      credit facilities (note 7)
                
                
                1,292,832
                
                
                
                702,993Long-
      term debt
      - convertible
      debentures (note 7)
                
                
                256,440
                
                
                
                285,792Asset
      ret ir ementobl
      igation (note 8)
                
                
                80,900
                
                
                
                49,614Long-
      term f
      inancial derivative instruments (not e 13)
                
                
                212,581
                
                
                
                43,336Ot
      her long- term liabilities (note 11)
                
                
                20,759
                
                
                
                16,305Fut
      ur e income taxes (note 12)
                
                
                450,000
                
                
                
                309,006N
      on- contr olling interests (not e 9)USOGP
      operations
                
                
                1,100,136
                
                
                
                81,111Subsequent
      event (note 16)Unitholders’
      equityUnit
      holders’ contr ibut ions (note 10)
                
                
                2,750,374
                
                
                
                2,254,048Convertible
      debent ures equity com ponent
                
                
                18,213
                
                
                
                18,522Contributed
      surplus (not e 11)
                
                
                801
                
                
                
                1,315Accumulated
      ot her compr ehensive (loss) incom e
                
                
                (69,188
                )
                
                
                (42,294
                )Accumulated
      income
                
                
                268,642
                
                
                
                238,208Accumulated
      cashdist ribut ions
                
                
                (1,260,177
                )
                
                
                (926,825
                )1,708,665
                
                
                
                1,542,974$
                5,758,792
                
                
                $
                3,370,919
  The
      accompanying notes to the consolidated financial statements are an
      integral part of these statements.On
      behalf of the Board of Directors:
                  
                  graphic
                graphic“signed”
                
                
                “signed”M.H.
      (Mike) Shaikh, FCA
                Thomas
      W. Buchanan, CADirector
                
                
                Director
 
 75
 
 PROVIDENT
      ENERGY TRUSTCONSOLIDATED
      STATEMENT OF OPERATIONS AND ACCUMULATED INCOMECanadian
      dollars (000s except per unit amounts)
  Year
      endedDecember
      31,2007
                
                
                2006RevenueRevenue
                
                $
                2,572,265
                
                
                $
                2,244,107Realized
      loss on financial derivative instruments
                
                
                (80,705
                )
                
                
                (13,540
                )Unrealized
      loss on financial derivative instruments
                
                
                (324,284
                )
                
                
                (43,314
                )2,167,276
                
                
                
                2,187,253ExpensesCost
      of goods sold
                
                
                1,605,782
                
                
                
                1,471,171Production,
      operating and maintenance
                
                
                208,180
                
                
                
                172,253Transportation
                
                
                28,120
                
                
                
                19,786Depletion,
      depreciation and accretion
                
                
                351,364
                
                
                
                249,139General
      and administrative (note 11)
                
                
                114,973
                
                
                
                97,288Interest
      on bank debt
                
                
                51,660
                
                
                
                34,666Interest
      and accretion on convertible debentures
                
                
                25,347
                
                
                
                23,919Amortization
      of deferred financing charges
                
                
                -
                
                
                
                3,854Foreign
      exchange loss (gain) and other
                
                
                6,795
                
                
                
                (2,319
                )Dilution
      gain (note 9)
                
                
                (260,324
                )
                
                
                -2,131,897
                
                
                
                2,069,757Income
      before taxes and non-controlling interests
                
                
                35,379
                
                
                
                117,496Capital
      tax expense
                
                
                3,762
                
                
                
                1,314Current
      and withholding tax expense
                
                
                6,362
                
                
                
                5,829Future
      income tax expense (recovery) (note 12)
                
                
                30,487
                
                
                
                (34,316
                )40,611
                
                
                
                (27,173
                )Net
      (loss) income before non-controlling interests
                
                
                (5,232
                )
                
                
                144,669Non-controlling
      interests (note 9)USOGP
      operations
                
                
                (35,666
                )
                
                
                2,995Exchangeable
      shares
                
                
                -
                
                
                
                754Net
      income
                
                
                30,434
                
                
                
                140,920Accumulated
      income, beginning of year
                
                $
                238,208
                
                
                $
                97,288Accumulated
      income, end of year
                
                $
                268,642
                
                
                $
                238,208Net
      income per unit – basic and diluted
                
                $
                0.13
                
                
                $
                0.72
 
 The
accompanying notes to the consolidated financial statements are an integral part
of these statements.
 76
 
 PROVIDENT
      ENERGY TRUSTCONSOLIDATED
      STATEMENT OF CASH FLOWSCanadian
      Dollars (000s)Year
      endedDecember
      31,2007
                
                
                2006Cash
      provided by operating activitiesNet
      income for the year
                
                $
                30,434
                
                
                $
                140,920Add
      (deduct) non-cash items:Depletion,
      depreciation and accretion
                
                
                351,364
                
                
                
                249,139Non-cash
      interest expense and other
                
                
                10,290
                
                
                
                6,357Non-cash
      unit based compensation (note 11)
                
                
                14,014
                
                
                
                23,083Unrealized
      loss on financial derivative instruments
                
                
                324,284
                
                
                
                43,314Unrealized
      foreign exchange loss and other
                
                
                3,372
                
                
                
                418Future
      income tax expense (recovery) (note 12)
                
                
                30,487
                
                
                
                (34,316
                )Dilution
      gain (note 9)
                
                
                (260,324
                )
                
                
                -Net
      (loss) income attributable to non-controlling interests
                
                
                (35,666
                )
                
                
                3,749Funds
      flow from operations
                
                
                468,255
                
                
                
                432,664Site
      restoration expenditures (note 14)
                
                
                (4,424
                )
                
                
                (4,622
                )Change
      in non-cash operating working capital
                
                
                624
                
                
                
                (13,693
                )464,455
                
                
                
                414,349Cash
      provided by financing activitiesIncrease
      in long-term debt
                
                
                534,215
                
                
                
                117,385Declared
      distributions to unitholders
                
                
                (333,352
                )
                
                
                (283,465
                )Declared
      distributions to non-controlling interests
                
                
                (35,846
                )
                
                
                (6,523
                )Issue
      of trust units, net of issue costs
                
                
                412,909
                
                
                
                257,076Contributions
      by non-controlling interests (note 9)
                
                
                683,100
                
                
                
                135,829Change
      in non-cash financing working capital
                
                
                2,179
                
                
                
                (154
                )1,263,205
                
                
                
                220,148Cash
      used for investing activitiesCapital
      expenditures
                
                
                (247,122
                )
                
                
                (190,433
                )Capitol
      Energy acquisition (note 4)
                
                
                (467,495
                )
                
                
                -Triwest
      Energy acquisition (note 4)
                
                
                (2,300
                )
                
                
                -USOGP
      natural gas asset acquisition (note 4)
                
                
                (763,652
                )
                
                
                -Acquisition
      of Midstream NGL business
                
                
                -
                
                
                
                (1,036
                )Oil
      and gas property acquisitions, net (note 4)
                
                
                (265,201
                )
                
                
                (481,625
                )Increase
      in investments
                
                
                (5,450
                )
                
                
                -Proceeds
      on sale of assets
                
                
                5,030
                
                
                
                11,517Change
      in reserve for future site reclamation (note 14)
                
                
                -
                
                
                
                1,872Change
      in non-cash investing working capital
                
                
                15,048
                
                
                
                3,397(1,731,142
                )
                
                
                (656,308
                )Decrease
      in cash and cash equivalents
                
                
                (3,482
                )
                
                
                (21,811
                )Cash
      and cash equivalents beginning of year
                
                
                10,302
                
                
                
                32,113Cash
      and cash equivalents end of year
                
                $
                6,820
                
                
                $
                10,302Supplemental
      disclosure of cash flow informationCash
      interest paid including debenture interest
                
                $
                69,600
                
                
                $
                56,036Cash
      taxes paid
                
                $
                13,741
                
                
                $
                9,601
 
 The
accompanying notes to the consolidated financial statements are an integral part
of these statements.
 77
 
 PROVIDENT
      ENERGY TRUSTCONSOLIDATED
      STATEMENT OF COMPREHENSIVE INCOME ANDACCUMULATED
      OTHER COMPREHENSIVE INCOMECanadian
      Dollars (000s)Year
      endedDecember
      31,2007
                
                
                2006Net
      income
                
                $
                30,434
                
                
                $
                140,920Other
      comprehensive (loss) income, net of taxesForeign
      currency translation adjustments
                
                
                (25,083
                )
                
                
                (509
                )Unrealized
      loss on available-for-sale investments(net
      of taxes of $262)
                
                
                (1,811
                )
                
                
                -(26,894
                )
                
                
                (509
                )Comprehensive
      income
                
                $
                3,540
                
                
                $
                140,411Accumulated
      other comprehensive (loss) income, beginning of year
                
                
                (42,294
                )
                
                
                (41,785
                )Other
      comprehensive (loss) income
                
                
                (26,894
                )
                
                
                (509
                )Accumulated
      other comprehensive (loss) income, end of year
                
                $
                (69,188
                )
                
                $
                (42,294
                )Accumulated
      income, end of year
                
                
                268,642
                
                
                
                238,208Accumulated
      cash disributions, end of year
                
                
                (1,260,177
                )
                
                
                (926,825
                )Retained
      earnings (deficit), end of year
                
                
                (991,535
                )
                
                
                (688,617
                )Total
      retained earnings (deficit) and accumulated other
      comprehensive(loss)
      income, end of year
                
                $
                (1,060,723
                )
                
                $
                (730,911
                )
 
 The
accompanying notes to the consolidated financial statements are an integral part
of these statements.
 78
 
  NOTES
TO THE CONSOLIDATED FINANCIAL STATEMENTS
 
 (Tabular
amounts in Cdn$ 000’s, except unit and per unit amounts)
 
 December
31, 2007
 
 1.
                Structure
      of the Trust
  Provident
      Energy Trust (the “Trust”) 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 directly and indirectly owned subsidiaries of
      the Trust (“Provident”). Cash flow is paid from Provident 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 and
      Provident, 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 numbers have been restated to conform to the current year
      presentation.
  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 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.
  79
 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 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
      two to 15 years. Capital assets related to pipelines 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.
  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
  80
 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 part of general and administrative expenses with
      an offsetting amount to 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.
  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.
  Marketing
      revenues and purchased product are recorded on a gross basis when
      Provident takes title to product and has the risks and rewards of
      ownership.
  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.
  81
 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, asset retirement obligation and future 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)Financial
      instruments
  Effective
      January 1, 2007, the Trust adopted the requirements of the Canadian
      Institute of Chartered Accountants (“CICA”) related to the new financial
      instruments accounting framework, which encompasses the following new CICA
      Handbook
      sections: 3855 Financial Instruments – Recognition and Measurement, 1530
      Comprehensive Income, and 3861 Financial Instruments – Disclosure and
      Presentation. The CICA Handbook section 3865 Hedges is effective January
      1, 2007, however, the Trust has elected not to apply hedge accounting,
      consistent with prior
periods.
  These
      new Handbook sections provide comprehensive requirements for the
      recognition and measurement of financial instruments, and introduce a new
      component of equity referred to as accumulated other comprehensive income
      (“AOCI”). In accordance with the transitional provisions of all of the new
      sections, the comparative interim consolidated financial statements have
      not been restated, except that the “Cumulative translation adjustment” has
      been reclassified to “Accumulated other comprehensive
    income”.
  Under
      these new standards, 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 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 long-term debt) are measured at amortized cost using
      the effective interest rate method. Transaction costs are included with
      the associated financial instrument and amortized
    accordingly.
  In
      conjunction with the above standards, the CICA issued 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. These two sections are effective for annual and interim periods
      relating to fiscal years beginning on or after October 1, 2007. The Trust
      is currently evaluating the effect that these standards might have on the
      consolidated financial statements.
  Several
      adjustments in the Trust’s consolidated financial statements were required
      upon transition to the new financial instruments framework, which were the
      following:
  Long-term
      debt and deferred financing charges
  Prior
      to the adoption of the new standards, financing charges related to
      long-term debt were included in “Deferred financing charges” on the
      Trust’s Consolidated Balance Sheet, and recognized in net income over the
      life of the debt.
 82
 Under
      the transitional provisions of Handbook section 3855 Financial Instruments
      – Recognition and Measurement, the Trust’s long-term debt – revolving
      credit facilities is now recorded at amortized cost using the effective
      interest rate method. The related financing charges have been included in
      the cost of the long-term debt. As a result of these
      changes, “Deferred financing charges” of $3.0 million, and prepaid
      interest of $8.5 million, which were previously recorded as assets of the
      Trust, were reclassified to “Long-term debt – revolving credit facilities”
      on the Consolidated Balance Sheet. The accounting treatment for “Long-term
      debt – convertible debentures” is the same as in prior periods, except
      that related deferred financing charges are now included in the carrying
      amount. Deferred financing charges of $9.4 million were reclassified to
      “Long-term debt – convertible debentures” on the Consolidated Balance
      Sheet.
  Comprehensive
      income
  The
      consolidated financial statements now include a new Consolidated Statement
      of Comprehensive Income and Accumulated Other Comprehensive Income. Other
      comprehensive income includes foreign currency translation adjustments
      relating to self-sustaining foreign operations and unrealized gains and
      losses on available-for-sale investments, net of the related future income
      tax on those items.
  ii)
                Equity
  In
      2005, the CICA issued Section 3251 “Equity”. This Section replaces Section
      3250 “Surplus” and establishes standards for the presentation of equity
      and changes in equity during the reporting period. The Section requires an
      entity to present separately each of the changes in equity during the
      period, including comprehensive income, as well as components of equity at
      the end of the period. This Section applies to interim and annual
      financial statements relating to fiscal years beginning on or after
      October 1, 2006. The application of this standard has not had a material
      impact on the Trust’s financial
statements.
  iii)
                Accounting
      changes
  In
      2006, the CICA released Section 1506 “Accounting Changes” which
      establishes criteria for changing accounting policies. Under the new
      section, voluntary changes in accounting policy are only made if they
      result in the financial statements providing reliable and more relevant
      information. Changes in accounting policy are applied retroactively unless
      it is impracticable to do so or the change in accounting policy is made on
      initial application of a primary source of GAAP, and that primary source
      of GAAP has specific transitional provisions. All material prior period
      errors are to be corrected retroactively. This section is effective for
      interim and annual financial statements for fiscal years beginning on or
      after January 1, 2007. The application of this standard has not had a
      material impact on the Trust’s financial
  statements.
  B.
                Recent
      accounting pronouncements
  i)
                Inventory
  In
      June 2007, the CICA issued a new accounting standard, Section 3031 -
      Inventories, which replaces the existing 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.
 The
      new Section is effective for the Trust beginning January 1, 2008. The
      Trust is currently evaluating the effect that this standard might have on
      the consolidated financial statements.
  ii)
                  Capital
      disclosures
  In
      2006, the CICA released 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. This section is effective for interim
      and annual financial statements relating to fiscal years beginning on or
      after October 1, 2007. The Trust is currently evaluating the effect that
      this standard might have on the consolidated financial
      statements.
 iii)
                  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 financial
  statements.
 83
  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:
  
 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 USOGP natural gas assets
  On
      November 1, 2007, BreitBurn Energy Partners L.P. (the “MLP”) completed the
      acquisition of certain assets from Quicksilver Resources Inc.
      (“Quicksilver”) in exchange for cash consideration of U.S. $750 million
      and 21,347,972 MLP units reducing Provident’s ownership in the MLP from
      approximately 50 percent to approximately 22 percent.  The
      assets acquired include all of Quicksilver’s natural gas, oil and related
      assets in Michigan, Indiana and
Kentucky.
  The
transaction has been accounted for as an asset purchase with the allocation of
cost as follows (in Canadian dollars):
 
 Property,
      plant and equipment
                
                $
                1,453,697Investments
      accounted for using the equity method
                
                
                15,600Intangible
      assets
                
                
                5,131Working
      capital, net
                
                
                15Asset
      retirement obligation
                
                
                (10,230
                )$
                1,464,213ConsiderationAcquisition
      costs
                
                
                12,952Cash
                
                $
                750,700763,652MLP
      units issued to Quicksilver
                
                
                700,561$
                1,464,213
 
 The
      cash portion of the consideration was financed by the issue of 16,666,667
      MLP units at U.S. $27.00 per unit (less underwriting fees and other costs
      of U.S. $8.7 million) and the MLP’s credit
  facility.
  iii)
                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:
  84
 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.
  iv)
                MLP
      acquisitions
  In
      May 2007, BreitBurn Energy Partners L.P. (the “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
      transactions were accounted for as asset purchases with the allocation of
      cost as follows (in Canadian
dollars):
 
 Property,
      plant and equipment
                
                $
                205,160Intangible
      assets
                
                
                3,591Inventory
                
                
                11,282Other
      working capital, net
                
                
                (821
                )Asset
      retirement obligation
                
                
                (4,708
                )$
                214,504
 The
acquisitions were financed by the issue of units by the MLP to institutional
investors (see note 9).
 v)
                Acquisition
      of Rainbow assets
  On
      August 31, 2006 Provident acquired a package of natural gas producing
      assets in the Rainbow and Peace River Arch areas of northwestern Alberta.
      The transaction was accounted for as an asset purchase with the allocation
      of the purchase price as follows:
  
 Net
      assets acquired and liabilities assumedProperty,
      plant and equipment
                
                $
                660,427Asset
      retirement obligation
                
                
                (1,903
                )Future
      income taxes
                
                
                (185,726
                )$
                472,798ConsiderationAcquisition
      costs
                
                $
                500Cash
                
                
                472,298$
                472,798
 
 The
acquisition was financed by the issuance of 16,325,000 units at $13.85 per unit
and Provident’s credit facilities.
 
 85
 
 5
                .
                Property,
      plant and equipment
  Accumulateddepletion
      and
                
                
                Net
      BookYear
      ended December 31, 2007
                
                Cost
                
                
                depreciation
                
                
                valueOil
      and natural gas properties
                
                $
                4,977,958
                
                
                $
                1,215,499
                
                
                $
                3,762,459Midstream
      assets
                
                
                790,434
                
                
                
                63,763
                
                
                
                726,671Office
      equipment
                
                
                40,936
                
                
                
                11,246
                
                
                
                29,690Total
                
                $
                5,809,328
                
                
                $
                1,290,508
                
                
                $
                4,518,820Accumulateddepletion
      and
                
                
                Net
      BookYear
      ended December 31, 2006
                
                Cost
                
                
                depreciation
                
                
                valueOil
      and natural gas properties
                
                $
                2,513,031
                
                
                $
                927,087
                
                
                $
                1,585,944Midstream
      assets
                
                
                781,092
                
                
                
                42,143
                
                
                
                738,949Office
      equipment
                
                
                17,070
                
                
                
                8,426
                
                
                
                8,644Total
                
                $
                3,311,193
                
                
                $
                977,656
                
                
                $
                2,333,537
 
 Costs
associated with unproved properties and major development projects excluded from
costs subject to depletion as at December 31, 2007 totaled $137.7 million
(December 31, 2006 - $17.8 million). Midstream assets include $35.9 million
(2006 - $22.0 million) for products required for line-fill and cavern
bottoms.
  An
impairment test calculation was performed on property, plant and equipment at
December 31, 2007 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,
2007:
 
 Oil
                
                
                Gas
                
                
                NGLYear
                
                $ /bbl
                
                
                $ /mcf
                
                
                $/bbl2008
                
                $
                60.10
                
                
                $
                6.80
                
                
                $
                63.712009
                
                $
                59.38
                
                
                $
                7.60
                
                
                $
                62.002010
                
                $
                59.24
                
                
                $
                7.87
                
                
                $
                60.982011
                
                $
                58.11
                
                
                $
                8.11
                
                
                $
                59.392012
                
                $
                58.55
                
                
                $
                8.37
                
                
                $
                59.91Thereafter
      (1)
                
                
                2.00
                %
                
                
                2.00
                %
                
                
                2.00
                %
 (1)Percentage change represents the increase in each year after 2012 to the
end of the reserve life.
  86
  6
                .
                Intangible
      assets
  Accumulated
                
                
                Net
      BookDecember
      31, 2007
                
                Cost
                
                amortization
                
                
                valueMidstream
      contracts and customer relationships
                
                $
                183,100
                
                
                $
                25,049
                
                
                $
                158,051Fractionation
      spread support agreement - Midstream
                
                
                17,600
                
                
                
                17,600
                
                
                
                -Other
      intangible assets - Midstream
                
                
                16,308
                
                
                
                2,566
                
                
                
                13,742U.S.
      oil and natural gas production related intangible assets
                
                
                8,468
                
                
                
                4,705
                
                
                
                3,763Total
                
                $
                225,476
                
                
                $
                49,920
                
                
                $
                175,556Accumulated
                
                
                Net
      BookDecember
      31, 2006
                
                Cost
                
                amortization
                
                
                valueMidstream
      contracts and customer relationships
                
                $
                183,100
                
                
                $
                12,842
                
                
                $
                170,258Fractionation
      spread support agreement - Midstream
                
                
                17,600
                
                
                
                9,258
                
                
                
                8,342Other
      intangible assets - Midstream
                
                
                16,308
                
                
                
                1,316
                
                
                
                14,992Total
                
                $
                217,008
                
                
                $
                23,416
                
                
                $
                193,592
   7
                .
                Long-term
      debt
  December
      31, 2007
                
                
                December
      31, 2006Revolving
      term credit facilities
                
                $
                1,292,832
                
                
                $
                702,993Convertible
      debentures
                
                
                275,638
                
                
                
                285,792Current
      portion of convertible debentures
                
                
                (19,198
                )
                
                
                -256,440
                
                
                
                285,792Total
                
                $
                1,549,272
                
                
                $
                988,785
 
 i)
                Revolving
      term credit facilities
  Provident
      has a $1,125 million term credit facility with a syndicate of Canadian
      chartered 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, 2006 the facility
      totaled $925 million. In May 2007 the facility was increased to its
      current level of $1,125 million. At December 31, 2007, $925.3 million was
      drawn on this facility. Included in the carrying value at December 31,
      2007 were financing costs of $1.3
million.
  The
      terms of the credit facility have a revolving three year period expiring
      on May 30, 2010. Provident 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 Provident
      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
      addition, Provident’s U.S. subsidiaries have credit facilities with a
      borrowing base of U.S. $737.7 million with a syndicate of U.S. banks
      secured by oil and gas assets of the subsidiaries. Provident’s U.S.
      subsidiaries may draw upon the facility by way of U.S. base rate loans,
      LIBOR loans or letters of credit. The facilities have a termination date
      of October 10, 2010. At December 31, 2007, $375.4 million was drawn on
      these facilities. Included in the carrying value at December 31, 2007 were
      financing costs of $6.6 million.
  At
      December 31, 2007 the effective interest rate of the outstanding credit
      facilities was 5.9 percent (2006 – 5.2 percent). At December 31, 2007
      Provident had $35.9 million in letters of credit outstanding (2006 - $31.9
      million) that guarantee Provident’s performance under certain commercial
      and other contracts.
  87
  ii)
                Convertible
      debentures
  The
      Trust may elect to satisfy interest and principal obligations by the issue
      of trust units. For the twelve months ended December 31, 2007, $6.1
      million of the face value of debentures were converted to trust units at
      the election of debenture holders (2006 - $15.4 million). Included in the
      carrying value at December 31, 2007 were financing costs of $7.0 million.
      The fair value of the convertible debentures at December 31, 2007
      approximates the face value of the instruments. The following table
      details each outstanding convertible
debenture.
  
 As
      at
                
                
                As
      atConvertible
      Debentures
                
                
                December
      31, 2007
                
                
                December
      31, 2006ConversionCarrying
                
                
                
                
                
                Carrying
                
                
                
                
                
                
                
                Price
      per($
      000s except conversion pricing)
                
                
                
                Value(1
                )
                
                Face
      Value
                
                
                
                Value(1
                )
                
                Face
      Value
                
                Maturity
      Date
                
                
                
                unit(2
                )6.5%
      Convertible Debentures
                
                
                $
                140,515
                
                
                $
                149,980
                
                
                $
                142,860
                
                
                $
                150,000
                
                April
      30, 2011
                
                
                
                14.756.5%
      Convertible Debentures
                
                
                
                91,460
                
                
                
                99,024
                
                
                
                93,134
                
                
                
                99,024
                
                Aug.
      31, 2012
                
                
                
                13.758.0%
      Convertible Debentures
                
                
                
                24,465
                
                
                
                25,109
                
                
                
                24,402
                
                
                
                25,114
                
                July
      31, 2009
                
                
                
                12.008.75%
      Convertible Debentures
                
                
                
                19,198
                
                
                
                19,931
                
                
                
                25,396
                
                
                
                25,972
                
                Dec.
      31, 2008
                
                
                
                11.05$
                275,638
                
                
                $
                294,044
                
                
                $
                285,792
                
                
                $
                300,110
 
 (1) Excluding
equity component of convertibl e 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
 
 8.
                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 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 $613.1million
(2006 - $411.6 million).  Payments to settle oil and gas asset
retirement obligations occur over the operating lives of the assets estimated to
be from two to 52 years.
  The total
undiscounted amount of future cash flows required to settle the midstream asset
retirement obligations is estimated to be $166.1million
(2006 - $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 29 to 40 years.
 
 Year
      ended December 31,($000s)
                
                2007
                
                
                2006Carrying
      amount, beginning of year
                
                $
                49,614
                
                
                $
                41,133Acquisitions
                
                
                17,442
                
                
                
                1,903Change
      in estimate
                
                
                14,561
                
                
                
                6,793Increase
      in liabilities incurred during the year
                
                
                2,547
                
                
                
                1,443Settlement
      of liabilities during the year
                
                
                (4,424
                )
                
                
                (4,622
                )Decrease
      in liabilities due to disposition
                
                
                (654
                )
                
                
                (946
                )Accretion
      of liability
                
                
                4,885
                
                
                
                3,822Foreign
      currency translation adjustments
                
                
                (3,071
                )
                
                
                88Carrying
      amount, end of year
                
                $
                80,900
                
                
                $
                49,614
 
  88
 
 9
                .
                Non-controlling
      interests – USOGP
  Year
      ended December 31,2007
                
                
                2006Non-controlling
      interests, beginning of year
                
                $
                81,111
                
                
                $
                11,885Net
      (loss) income attributable to non-controlling interests
                
                
                (35,666
                )
                
                
                2,995Distributions
      to non-controlling interests
                
                
                (35,846
                )
                
                
                (6,523
                )Investments
      by non-controlling interests
                
                
                1,129,073
                
                
                
                72,754Foreign
      currency translation adjustment
                
                
                (38,536
                )
                
                
                -Non-controlling
      interests, end of year
                
                $
                1,100,136
                
                
                $
                81,111Accumulated
      (loss) income attributable to non-controlling interests
                
                $
                (30,152
                )
                
                $
                5,514
 
 A
non-controlling interest arose from Provident’s June 15, 2004 acquisition of 92
percent of BreitBurn Energy Company L.P. (BreitBurn) of Los Angeles,
California.  Additional investments since June 2004 by Provident in
BreitBurn have reduced the non-controlling interest percentage at December 31,
2007 to approximately4.0percent
(2006 – 4.4 percent). Contributions by this non-controlling interest were nil in
2007 (2006 – $0.5 million).
  In the
second quarter of 2006, a USOGP subsidiary began a land development project with
a partner. The subsidiary has a 20 percent interest, with the partner holding 80
percent. Because the subsidiary stands to receive a majority share of the future
proceeds, Provident is consolidating the results in its statements, with the
partner’s interest recorded as non-controlling interest. Contributions by the
non-controlling interest total $3.9million
in 2007 (2006 - $3.7 million).
  In the
fourth quarter of 2006, Provident’s subsidiary, BreitBurn Energy Partners, L.P.
(the “MLP”) completed its initial public offering. BreitBurn transferred oil and
gas properties comprising approximately half of its proved reserves and two
thirds of its daily production to the MLP. The offering of 6.9 million common
units at U.S. $18.50 per unit resulted in approximately 34 percent of the MLP
held by partners not related to Provident. During the second quarter of 2007,
the MLP issued 7.0 million common units to third parties for proceeds of $237.5
million.  As a result of this transaction, Provident’s interest in the
MLP decreased from approximately 66 percent to approximately 50 percent,
resulting in a dilution gain of $98.6 million recorded on the consolidated
statement of operations. During the fourth quarter of 2007, the MLP issued 38.0
million units in conjunction with the USOGP natural gas asset
acquisition.  The cash proceeds and ascribed value of these issued
units totaled $1,142.2 million. As a result of this transaction, Provident’s
interest in the MLP decreased from approximately 50 percent to approximately 22
percent, resulting in an additional dilution gain of $161.7 million recorded on
the consolidated statement of operations. The non-controlling interest balance
increased by $1,119.4 million in 2007 reflecting the non-controlling interest
ownership change from approximately 34 percent to approximately 78
percent.  The Trust, through its 95.6 percent general partnership
interest, continues to control and consolidate the MLP.
 
 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.
 
 i)  
2007 activity
 
 On May
24, 2007, the Trust issued 25,490,197 Subscription Receipts at a price of $12.75
per Subscription Receipt for total proceeds of $325 million ($308.3 million net
of issue costs).  On June 7, 2007, an additional 3,823,530
Subscription Receipts were issued at a price of $12.75 on exercise of the
underwriter’s over-allotment option, for additional proceeds of $48.8 million
($46.3 million net of issue costs). Each Subscription Receipt entitled the
holder to receive one trust unit upon completion of the Capitol acquisition. The
acquisition closed on June 19, 2007 at which time all the outstanding
Subscription Receipts were converted into trust units. Proceeds from the issue
were used to fund the Capitol acquisition.
  89
 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 net increase in unitholders’ contributions
associated with these activities was $65.2 million.
 
 ii) 
2006 activity
 
 On July
31, 2006 the Trust issued 16,325,000 Subscription Receipts at a price of $13.85
per Subscription Receipt for total proceeds of $226.1 million ($214.2 million
net of issue costs). Each Subscription Receipt entitled the holder to receive
one trust unit upon completion of the Rainbow asset acquisition. The acquisition
closed on August 31, 2006 at which time all the outstanding Subscription
Receipts were converted into trust units. At that time, the holders of the
Subscription Receipts were also entitled to $0.12 per trust unit, which is the
equivalent of the August distribution paid in September. This payment was
treated as a reduction to the proceeds received for the units issued through the
Subscription Receipts to $13.73 per trust unit, reducing the amount attributed
to Unitholders’ contributions by $2.0 million. Proceeds from the issue were used
to fund the Rainbow asset acquisition.
  
 In 2006,
the Trust issued 6.1 million units related to Provident’s DRIP program,
conversion of exchangeable shares to units, conversion of convertible debentures
to units and units issued pursuant to Provident’s Unit Option Plan. The net
increase in unitholders’ contributions associated with these activities was
$70.1 million.
 
 Year
      ended December 31,2007
                
                
                
                
                
                2006Amount
                
                
                Number
      of
                
                
                AmountTrust
      Units
                
                Number
      of units
                
                
                
                (000s
                )
                
                units
                
                
                
                (000s
                )Balance
      at beginning of year
                
                
                211,228,407
                
                
                $
                2,254,048
                
                
                
                188,772,788
                
                
                $
                1,971,707Issued
      for cash
                
                
                29,313,727
                
                
                
                373,750
                
                
                
                16,325,000
                
                
                
                224,142Issued
      to acquire Triwest Energy Inc.
                
                
                6,251,149
                
                
                
                76,577
                
                
                
                -
                
                
                
                -Exchangeable
      share conversions
                
                
                -
                
                
                
                -
                
                
                
                881,083
                
                
                
                9,012Issued
      pursuant to unit option plan
                
                
                825,349
                
                
                
                8,426
                
                
                
                907,201
                
                
                
                8,589Issued
      pursuant to the distribution reinvestment plan
                
                
                3,941,864
                
                
                
                45,338
                
                
                
                2,714,636
                
                
                
                33,045To
      be issued pursuant to the distribution reinvestment plan
                
                
                525,822
                
                
                
                5,153
                
                
                
                300,134
                
                
                
                3,806Debenture
      conversions
                
                
                548,455
                
                
                
                6,270
                
                
                
                1,327,565
                
                
                
                15,689Unit
      issue costs
                
                
                -
                
                
                
                (19,188
                )
                
                
                -
                
                
                
                (11,942
                )Balance
      at end of year
                
                
                252,634,773
                
                
                $
                2,750,374
                
                
                
                211,228,407
                
                
                $
                2,254,048
 
 The basic
per trust unit amounts for 2007 were calculated based on the weighted average
number of units outstanding of 229,939,158 (2006 – 196,627,060). The diluted per
trust unit amounts for 2007 are calculated including no additional trust units
(2006 – 286,957) 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’s Canadian and U.S. subsidiaries 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 or U.S.
      subsidiary 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, 2007 there were 1,408,196 RTUs and 4,441,152 PTUs
      outstanding (2006 – 571,423 RTUs and 1,704,234 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, 2007, $12.7 million
      (2006 - $2.3 million) is included in accounts payable and accrued
      liabilities for this plan and $14.8 million (2006 - $13.3 million) is
      included in other long-term liabilities. The following table reconciles
      the expense recorded for RTUs and
PTUs.
  90
 
  Year
      ended December 31,2007
                
                
                2006Cash
      general and administrative
                
                $
                2,395
                
                
                $
                1,021Non-cash
      unit based compensation (included in general and
      administrative)
                
                
                11,576
                
                
                
                11,156Production,
      operating and maintenance expense
                
                
                1,247
                
                
                
                939$
                15,218
                
                
                $
                13,116
 
 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 replaces the unit option plan. Unit
      options in existence will continue to be
  outstanding.
  At
      December 31, 2007, the Trust had 1,279,169 options outstanding and
      exercisable with strike prices ranging between $10.49 and $12.14 per unit.
      The weighted average remaining contractual life of the options was 0.87
      years and the weighted average exercise price was $11.04 per unit
      excluding average potential reductions to the strike prices of $1.77 per
      unit.
  At
      December 31, 2006, the Trust had 2,114,808 options outstanding with strike
      prices ranging between $10.49 and $12.14 per unit. The weighted average
      remaining contractual life of the options was 1.96 years and the weighted
      average exercise price was $11.09 per unit excluding average potential
      reductions to the strike prices of $1.50 per unit. Of these outstanding
      options, 1,947,989 were exercisable with a weighted average price of
      $11.08.
  The
      following table reconciles the movement in the contributed surplus
      balance.
  
 Year
      ended December 31,2007
                
                
                2006Contributed
      surplus, beginning of the year
                
                $
                1,315
                
                
                $
                1,675Non-cash
      unit based compensation (included in general and
      administrative)
                
                
                57
                
                
                
                203Benefit
      on options exercised charged to unitholders’ equity
                
                
                (571
                )
                
                
                (563
                )Contributed
      surplus, end of year
                
                $
                801
                
                
                $
                1,315
 
 iii)
                Unit
      appreciation rights
  At
      December 31, 2007, the Trust’s U.S. subsidiaries had unit appreciation
      rights (UARs) outstanding of 187,656 (2006 – 472,521) with a weighted
      average price of U.S. $9.58 (2006 – U.S. $8.41). Of these outstanding
      UARs, 148,336 (2006 – 81,852) were exercisable at a weighted average price
      of U.S. $9.46 (2006 – U.S. $8.46).
  The
      fair value associated with the UARs is expensed in the statement of
      operations over the vesting period. At December 31, 2007, $0.8 million
      (2006 - $2.5 million) is included in accounts payable and accrued
      liabilities for this plan and nil (2006 - $0.1 million) is included in
      other long-term liabilities. The following table reconciles the expense
      recorded for UARs
  
 Year
      ended December 31,2007
                
                
                2006Cash
      general and administrative
                
                $
                2,113
                
                
                $
                798Non-cash
      unit based compensation(included
      in general and administrative)
                
                
                (1,490
                )
                
                
                1,246$
                623
                
                
                $
                2,044
  iv)
                Other
      unit based compensation
  Pursuant
      to employment agreements between the Trust’s U.S. subsidiaries and certain
      employees, the employees are eligible to receive cash compensation in
      relation to the value of a specified number of underlying notional
      units.
 91
 The
      value of each notional unit is determined on the basis of a valuation of
      the U.S. subsidiaries as at the end of the fiscal period. At December 31,
      2007 there were 3,061,137 notional units outstanding under the key
      employee plan (2006 – 2,755,566). There were 2,965,502 notional units
      outstanding under other USOGP unit based plans (2006 – 12,984,001).
      At December 31, 2007, $8.7 million (2006 - $13.4 million) is included in
      accounts payable and accrued liabilities for these plans, and $6.0 million
      (2006 - $2.9 million) is included in other long-term
      liabilities.
   The
      following table reconciles the expense recorded for the other unit based
      compensation plans.Year
      ended December 31,2007
                
                
                2006Cash
      general and administrative
                
                $
                11,189
                
                
                $
                3,807Non-cash
      unit based compensation(included
      in general and administrative)
                
                
                3,871
                
                
                
                10,478$
                15,060
                
                
                $
                14,285
  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 now 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 new
legislation, the estimated effective tax rate on temporary difference reversals
after 2011 may change in future periods.  As the legislation is new,
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.
  Provident
follows the liability method for calculating future income taxes. Under this
method, future income tax assets and liabilities are recognized based on the
estimated tax effects of temporary differences in the carrying value of assets
and liabilities and their respective tax bases, using income tax rates
substantively enacted on the consolidated balance sheet date:
 
 Year
      ended December 31,Future
      income taxes
                
                2007
                
                
                2006Petroleum
      and natural gas properties, production facilities and
other
                
                $
                332,301
                
                
                $
                266,156Midstream
      facilities
                
                
                117,699
                
                
                
                42,850$
                450,000
                
                
                $
                309,006
  92
  
 The
income tax provision differs from the expected amount calculated by applying the
Canadian combined federal and provincial income tax rate of 32.81 percent (2006
– 34.67 percent) as follows:
 
 Year
      ended December 31,2007
                
                
                2006Expected
      income tax expense
                
                $
                23,310
                
                
                $
                40,736Increase
      (decrease) resulting from:Future
      income tax expense relating to enactment of Bill C-52,Budget
      Implementation Act 2007
                
                
                88,352
                
                
                
                -Non-deductible
      Crown charges and other payments
                
                
                -
                
                
                
                8,135Federal
      resource allowance
                
                
                -
                
                
                
                (5,742
                )Alberta
      Royalty Tax Credit
                
                
                -
                
                
                
                (173
                )Income
      of the Trust and other
                
                
                (73,045
                )
                
                
                (70,999
                )Capital
      Taxes
                
                
                3,762
                
                
                
                1,314Witholding
      tax and other
                
                
                3,425
                
                
                
                3,308Income
      tax rate changes
                
                
                (5,193
                )
                
                
                (3,752
                )Income
      tax expense (recovery)
                
                $
                40,611
                
                
                $
                (27,173
                )
  13.
                
                Financial
      instruments
 
 Financial
instruments of the Trust carried on the consolidated balance sheet consist
mainly of cash and cash equivalents, accounts receivable, current liabilities,
commodity, foreign currency and interest rate contracts and long-term debt.
Except as disclosed in note 7, as at December 31, 2007 and 2006, there were no
significant differences between the carrying value of these financial
instruments and their estimated fair value.
  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 the Trust’s assessment of the creditworthiness of such
counterparties.  The carrying value of accounts receivable reflects
management's assessment of the associated credit risks. With respect to
counterparties to financial instruments, the Trust partially mitigates
associated credit risk by limiting transactions to counterparties with
investment grade credit ratings and obtaining financial guarantees from certain
counterparties.
  Provident’s
commodity price risk management program is intended to minimize the volatility
of commodity prices and to assist with stabilizing cash flow and distributions.
Provident seeks to accomplish this through the use of financial instruments from
time to time to reduce its exposure to fluctuations in commodity prices and
foreign exchange rates.
  With
respect to financial instruments, Provident could be exposed to losses if a
counterparty fails to perform in accordance with the terms of the
contract.  This risk is managed by diversifying the derivative
portfolio among counterparties meeting certain financial criteria.
 
 i)
                Commodity
      price
  a)
                Crude
      oil
  In
      2007, Provident paid $17.6 million (2006 - $5.7 million) to settle various
      oil market based contracts on an aggregate volume of 3.4 million barrels
      (2006 – 2.1 million barrels). The estimated value of contracts in place if
      settled at market prices at December 31, 2007 would have resulted in an
      opportunity cost of $98.2 million (2006 – $7.2 million
    gain).
  b)
                Natural
      Gas
  In
      2007, Provident received $9.6 million (2006 - $7.6 million) to settle
      various natural gas market based contracts on an aggregate of 16.7 million
      gigajoules (“gj”) (2006 – 9.5 million gj’s). The estimated value of
      contracts in place if settled at market prices at December 31, 2007 would
      have resulted in an opportunity cost of $18.0 million (2006 – $8.6 million
      gain).
  c)
                Midstream
  93
 
 In 2007,
Provident received $17.9 million (2006 – paid $0.6 million) to settle Midstream
oil market based contracts on an aggregate volume of 1.2 million barrels (2006 -
1.5 million barrels) and paid $48.7 million (2006 -$27.1 million) to settle
Midstream natural gas market based contracts on an aggregate volume of 25.3
million gj’s (2006 – 15.3 million gj’s).  In addition, Provident paid
$48.2 million (2006 – received $12.3 million) to settle Midstream NGL market
based contracts on an aggregate volume of 7.2 million barrels (2006 – 2.5
million barrels). The estimated value of contracts in place if settled at market
prices at December 31, 2007 would have resulted in an opportunity cost of $261.6
million (2006 – $68.8 million).
 
 ii)
                Foreign
      exchange contracts
  In
      2007, Provident received $6.3 million to settle various foreign exchange
      based contracts (2006 - $0.4 million). The estimated value of contracts in
      place if settled at foreign exchange rates at December 31, 2007 would have
      resulted in an opportunity cost of $0.1 million (2006 – $0.1 million
      gain).
  iii)
                Interest
      rate contracts
  As
      at December 31, 2007 the estimated value of contracts in place settled at
      December 31 interest rates was an opportunity cost of $0.1 million
      (December 31, 2006 – nil).
  94
  The
      contracts in place at December 31, 2007 are summarized in the following
      tables:COGPVolumeYear
      Product
                (Buy)Sell
                Terms
                Effective
      Period2008
                Crude
      Oil
                250
                Bpd
                Puts
      US $63.75 per bbl
                January
      1 - December 31150
                Bpd
                Puts
      US $75.00 per bbl
                January
      1 - December 311,000
                Bpd
                Puts
      US $67.50 per bbl
                January
      1 - December 31250
                Bpd
                Participating
      Swap US $60.00 per bbl (max to 75.3% above the floor
price)
                January
      1 - December 31375
                Bpd
                Participating
      Swap US $65.00 per bbl (52.7% above the floor price)
                January
      1 - December 31450
                Bpd
                Participating
      Swap US $62.50 per bbl (max to 52.5% above the floor
price)
                January
      1 - June 30450
                Bpd
                Participating
      Swap US $62.50 per bbl (67.8% above the floor price)
                January
      1 - June 30850
                Bpd
                Participating
      Swap US $65.00 per bbl (57.5% above the floor price)
                January
      1 - June 30850
                Bpd
                Participating
      Swap US $62.50 per bbl (max to 69.9% above the floor
price)
                January
      1 - June 30300
                Bpd
                Participating
      Swap US $62.50 per bbl (max to 51% above the floor price)
                July
      1 - December 31625
                Bpd
                Participating
      Swap US $65.00 per bbl (54.25% above the floor price)
                July
      1 - December 31925
                Bpd
                Participating
      Swap US $62.50 per bbl (66% above the floor price)
                July
      1 - December 31325
                Bpd
                Participating
      Swap US $67.20 per bbl (70% above the floor price)
                July
      1 - December 31Natural
      Gas
                1,000
                Gjpd
                Puts
      Cdn $6.00 per gj
                January
      - March 315,000
                Gjpd
                Participating
      Swap Cdn $6.48 per gj (max to 100% above the floor price)
                January
      - March 314,000
                Gjpd
                Participating
      Swap Cdn $7.00 per gj (52.8% above the floor price)
                January
      - March 312,000
                Gjpd
                Participating
      Swap Cdn $7.00 per gj (max to 70% above the floor price)
                January
      - March 314,000
                Gjpd
                Participating
      Swap Cdn $7.25 per gj (56% above the floor price)
                January
      - March 318,000
                Gjpd
                Participating
      Swap Cdn $7.50 per gj (70% above the floor price)
                January
      - March 318,000
                Gjpd
                Participating
      Swap Cdn $7.75 per gj (70% above the floor price)
                January
      - March 312,000
                Gjpd
                Participating
      Swap Cdn $8.00 per gj (max to 75.5% above the floor price)
                January
      - March 31300
                Gjpd
                Participating
      Swap Cdn $7.60 per gj (53.5% above the floor price)
                January
      1 - June 302,000
                Gjpd
                Participating
      Swap Cdn $6.00 per gj (max up to 85% above the floor
price)
                January
      1 - October 312,000
                Gjpd
                Participating
      Swap Cdn $7.50 per gj (max to 25% above the floor price)
                January
      1 - October 31900
                Gjpd
                Participating
      Swap Cdn $7.60 per gj (41% above the floor price)
                January
      1 - October 312,000
                Gjpd
                Participating
      Swap Cdn $6.00 per gj (56% above the floor price)
                April
      1 - October 312,000
                Gjpd
                Participating
      Swap Cdn $7.00 per gj (48.6% above the floor price)
                April
      1 - October 311,000
                Gjpd
                Participating
      Swap Cdn $6.75 per gj (51% above the floor price)
                April
      1 - December 311,000
                Gjpd
                Participating
      Swap Cdn $7.00 per gj (max up to 85% above the floor
price)
                April
      1 - December 311,000
                Gjpd
                Participating
      Swap Cdn $7.50 per gj (max to 23.5% above the floor price)
                April
      1 - December 311,000
                Gjpd
                Participating
      Swap Cdn $6.50 per gj (50% above the floor price)
                November
      1 - December 311,000
                Gjpd
                Participating
      Swap Cdn $6.50 per gj (max up to 90% above the floor
price)
                November
      1 - December 312,000
                Gjpd
                Participating
      Swap Cdn $6.75 per gj (max up to 90% above the floor
price)
                November
      1 - December 312,000
                Gjpd
                Participating
      Swap Cdn $7.00 per gj (max up to 85% above the floor
price)
                November
      1 - December 312,000
                Gjpd
                Participating
      Swap Cdn $7.50 per gj (max up to 100% above the floor
    price)
                November
      1 - December 31400
                Gjpd
                Participating
      Swap Cdn $7.75 per gj (23% above the floor price)
                November
      1 - December 312009
                Crude
      Oil
                125
                Bpd
                Participating
      Swap US $60.00 per bbl (60% above the floor price)
                January
      1 - December 31825
                Bpd
                Participating
      Swap US $62.50 per bbl (59.5% above the floor price)
                January
      1 - December 31400
                Bpd
                Participating
      Swap US $62.50 per bbl (max to 50% above the floor price)
                January
      1 - June 301,500
                Bpd
                Participating
      Swap US $62.50 per bbl (62.6% above the floor price)
                January
      1 - June 30775
                Bpd
                Participating
      Swap US $62.50 per bbl (60.4% above the floor price)
                July
      1 - December 31Natural
      Gas
                400
                Gjpd
                Participating
      Swap Cdn $7.75 per gj (23% above the floor price)
                January
      1 - December 311,000
                Gjpd
                Participating
      Swap Cdn $6.50 per gj (50% above the floor price)
                January
      1 - March 311,000
                Gjpd
                Participating
      Swap Cdn $6.50 per gj (max up to 90% above the floor
price)
                January
      1 - March 311,000
                Gjpd
                Participating
      Swap Cdn $6.75 per gj (51% above the floor price)
                January
      1 - March 312,000
                Gjpd
                Participating
      Swap Cdn $6.75 per gj (max up to 90% above the floor
price)
                January
      1 - March 311,000
                Gjpd
                Participating
      Swap Cdn $7.00 per gj (max up to 85% above the floor
price)
                January
      1 - March 312,000
                Gjpd
                Participating
      Swap Cdn $7.00 per gj (max up to 85% above the floor
price)
                January
      1 - March 313,000
                Gjpd
                Participating
      Swap Cdn $7.50 per gj (max to 62% above the floor price)
                January
      1 - March 31
 
 95
 
 USOGPVolumeYear
      Product
                (Buy)Sell
                Terms
                Effective
      Period2008
                Crude
      Oil
                125-325
      Bpd
                US
      $59.25 per bbl
                January
      1 -
      December 31325
                Bpd
                US
      $70.37 per bbl
                January
      1 -
      December 31790
                Bpd
                US
      $72.89 per bbl
                January
      1 -
      December 31425
                Bpd
                Participating
      Swap US $60.00 per bbl (max to 76% above the floor price)
                January
      1 - December 312,650
                Bpd
                US
      $68.44 per bbl
                January
      1 -
      June 30250
                Bpd
                Costless
      Collar US $66.00 floor, US $69.25 ceiling
                January
      1 -
      June 30250
                Bpd
                Costless
      Collar US $66.00 floor, US $71.50 ceiling
                January
      1 -
      June 30250
                Bpd
                US
      $71.24 per bbl
                July
      1 - September 302,500
                Bpd
                Participating
      Swap US $60.00 per bbl (max to 53.3% above the floor
price)
                July
      1 - September 30250
                Bpd
                US
      $70.66 per bbl
                July
      1 - December 31250
                Bpd
                Participating
      Swap US $70.00 per bbl (61.8% above the floor price)
                July
      1 - December 312,000
                Bpd
                Participating
      Swap US $60.00 per bbl (max to 59% above the floor price)
                October
      1 - December 31750
                Bpd
                US
      $70.49 per bbl
                October
      1 - December 31150
                Bpd
                Participating
      Swap US $60.00 per bbl (78% above the floor price)
                January
      1 -
      December 31250
                Bpd
                Participating
      Swap US $62.50 per bbl (57.5% above the floor price)
                January
      1 -
      December 31250
                Bpd
                Participating
      Swap US $65.00 per bbl (52% above the floor price)
                January
      1 -
      December 31Natural
      Gas
                48,643
                Mmbtu
                US
      $8.01 per mmbtu (10)
                January
      1 - December 312009
                Crude
      Oil
                125
      - 325 Bpd
                US
      $59.25 per bbl
                January
      1 -
      December 31460
                Bpd
                US
      $69.95 per bbl
                January
      1 -
      December 31679
                Bpd
                US
      $71.38 per bbl
                January
      1 -
      December 31410
                Bpd
                Participating
      Swap US $60.00 per bbl (max to 67.99% above the floor
    price)
                January
      1 - December 31250
                Bpd
                Participating
      Swap US $62.50 per bbl (max to 67.25% above the floor
    price)
                January
      1 - December 31210
                Bpd
                Costless
      Collar US $60.00 floor, US $79.50 ceiling
                January
      1 -
      December 31250
                Bpd
                Participating
      Swap US $70.00 per bbl (61.8% above the floor price)
                January
      1 -
      December 31500
                Bpd
                Participating
      Swap US $60.00 per bbl (max to 55.5% above the floor
price)
                January
      1 -
      September 302,000
                Bpd
                Participating
      Swap US $60.00 per bbl (max to 59% above the floor price)
                January
      1 - September 30500
                Bpd
                US
      $70.92 per bbl
                January
      1 -
      March 31500
                Bpd
                US
      $72.25 per bbl
                April
      1 - June 30250
                Bpd
                US
      $72.47 per bbl
                October
      1 - December 31250
                Bpd
                Participating
      Swap US $60.00 per bbl (70% above the floor price)
                October
      1 - December 31500
                Bpd
                Participating
      Swap US $65.00 per bbl (54% above the floor price)
                October
      1 - December 31500
                Bpd
                Participating
      Swap US $65.00 per bbl (50% above the floor price)
                October
      1 - December 31250
                Bpd
                US
      $70.00 per bbl
                December
      1 - December 31425
                Bpd
                Participating
      Swap US $60.00 per bbl (61.45% above the floor price)
                January
      1 - December 31Natural
      Gas
                44,071
                Mmbtu
                US
      $8.01 per mmbtu (10)
                January
      1 - December 312010
                Crude
      Oil
                609
                Bpd
                US
      $70.42 per bbl
                January
      1 -
      December 31500
                Bpd
                US
      $69.75 per bbl
                January
      1 -
      December 31933
                Bpd
                Participating
      Swap US $60.00 per bbl (max to 59.01% above the floor
    price)
                January
      1 - December 31250
                Bpd
                Participating
      Swap US $62.50 per bbl (56.20% above the floor price)
                January
      1 - December 31183
                Bpd
                Costless
      Collar US $60.00 floor, US $79.25 ceiling
                January
      1 -
      December 31183
                Bpd
                US
      $69.59 per bbl
                January
      1 -
      December 31250
                Bpd
                Participating
      Swap US $70.00 per bbl (61.8% above the floor price)
                January
      1 -
      March 31250
                Bpd
                Participating
      Swap US $60.00 per bbl (70% above the floor price)
                January
      1 -
      June 30500
                Bpd
                Participating
      Swap US $65.00 per bbl (50% above the floor price)
                January
      1 -
      June 30250
                Bpd
                US
      $72.47 per bbl
                January
      1 -
      June 30542
                Bpd
                US
      $72.05 per bbl
                January
      1 -
      July 31500
                Bpd
                Participating
      Swap US $70.00 per bbl (37.3% above the floor price)
                April
      1 - September 30Natural
      Gas
                40,471
                Mmbtu
                US
      $8.01 per mmbtu (10)
                January
      1 - December 312011
                Crude
      Oil
                1,377
                Bpd
                Participating
      Swap US $60.00 per bbl (max to 53.11% above the floor
    price)
                January
      1 - December 31177
                Bpd
                Costless
      Collar US $60.00 floor, US $77.60 ceiling
                January
      1 -
      December 31177
                Bpd
                US
      $69.15 per bbl
                January
      1 -
      December 31Natural
      Gas
                40,400
                Mmbtu
                US
      $8.01 per mmbtu (10)
                January
      1 - March 31
 
 96
  
 MidstreamVolumeYear
                Product
                (Buy)Sell
                Terms
                Effective
      Period2008
                Crude
      Oil
                2,250
                Bpd
                Costless
      Collar US $68.50 floor, US $73.72 ceiling
                January
      1 - December 31500
                Bpd
                Costless
      Collar US $64.00 floor, US $74.50 ceiling
                January
      1 - September 30500
                Bpd
                Costless
      Collar US $73.00 floor, US $80.00 ceiling
                January
      1 - June 30250
                Bpd
                US
      $65.60 per bbl
                January
      1 - December 31250
                Bpd
                US
      $66.65 per bbl
                January
      1 - December 319,635
                Bpd
                Cdn
      $76.02 per bbl
                January
      1 - December 31(845
                Bpd
                US
      $74.64 per bbl (4)
                January
      1 - March 31(10,535
                Bpd
                US
      $86.93 per bbl (4)
                January
      1 - March 31Natural
      Gas
                (75,767
                Gjpd
                Cdn
      $8.31 per gj
                January
      1 - December 31Foreign
      Exchange
                
                
                Sell
      US $6,202,175 per month @1.1198 (5)
                January
      1 - December 31Sell
      US $1,107,166 per month @1.1035 (5)
                January
      1 - June 30Sell
      US $974,222 per month @1.1255 (5)
                January
      1 - September 30Propane
                3,225
                Bpd
                US
      $1.5308 per gallon (6)(9)
                January
      1 - January 311,206
                Bpd
                US
      $1.5382 per gallon (6)(9)
                February
      1 - February 295,645
                Bpd
                US
      $1.2829 per gallon (6)(9)
                January
      1 - February 29850
                Bpd
                US
      $1.2487 per gallon (4)(6)
                January
      1 - March 3110,287
                Bpd
                US
      $1.4595 per gallon (4)(6)
                January
      1 - March 31Normal
      Butane
                2,258
                Bpd
                US
      $1.8148 per gallon (7)(9)
                January
      1 - January 312,230
                Bpd
                US
      $1.647 per gallon (4)(7)
                January
      1 - March 31150
                Bpd
                US
      $1.4325 per gallon (4)(7)
                January
      1 - March 31ISO
      Butane
                150
                Bpd
                US
      $1.4453 per gallon (4)(8)
                January
      1 - March 311,720
                Bpd
                US
      $1.6424 per gallon (4)(8)
                January
      1 - March 31Power
                (20
                MW/hpd
                Cdn
      $76.43 per MW/h (12)
                January
      1 - December 312009
                Crude
      Oil
                2,500
                Bpd
                Costless
      Collar US $64.80 floor, US $69.36 ceiling
                January
      1 - December 317,158
                Bpd
                Cdn
      $74.23 per bbl
                January
      1 - December 31250
                Bpd
                US
      $64.60 per bbl
                January
      1 - December 31250
                Bpd
                US
      $66.65 per bbl
                January
      1 - December 31500
                Bpd
                Costless
      Collar US $70.00 floor, US $79.00 ceiling
                January
      1 - June 301,000
                Bpd
                Participating
      Swap US $63.13 per bbl (56% above the floor price)
                July
      1 - August 31598
                Bpd
                Participating
      Swap US $75.64 per bbl (55.7% above the floor price)
                July
      1 - November 30500
                Bpd
                Participating
      Swap Cdn $73.38 per bbl (48.9% above the floor price)
                September
      1 - November 30Natural
      Gas
                (60,769
                Gjpd
                Cdn
      $8.14 per gj
                January
      1 - December 31(2,792
                Gjpd
                Participating
      Swap Cdn $7.73 per gj (39% below the ceiling price)
                July
      1 - November 30(2,810
                Gjpd
                Cdn
      $6.62 per gj
                September
      1 - October 31(2,810
                Gjpd
                Costless
      Collar Cdn $6.20 floor, Cdn $7.10 ceiling
                September
      1 - October 31Foreign
      Exchange
                
                
                Sell
      US $6,699,029 per month @1.1113 (5)
                January
      1 - December 31Sell
      US $1,055,833 per month @1.099 (5)
                January
      1 - June 30Sell
      US $1,972,561 per month @1.0245 (5)
                July
      1 - August 31Sell
      US $596,166 per month @0.9815 (5)
                July
      1 - October 31Sell
      US $1,686,650 per month @0.9620 (5)
                September
      1 - October 31Sell
      US $1,163,100 per month @1.013 (5)
                November
      1 - November 302010
                Crude
      Oil
                1,500
                Bpd
                Costless
      Collar US $62.90 floor, US $67.48 ceiling
                January
      1 - December 316,502
                Bpd
                Cdn
      $73.16 per bbl
                January
      1 - December 31250
                Bpd
                US
      $66.65 per bbl
                January
      1 - December 31500
                Bpd
                Participating
      Swap Cdn $61.50 per bbl (50% above the floor price)
                July
      1 - August 31376
                Bpd
                Participating
      Swap Cdn $70.91 per bbl (56% above the floor price)
                July
      1 - October 31820
                Bpd
                Participating
      Swap US $73.63 per bbl (51.8% above the floor price)
                January
      1 - November 30Natural
      Gas
                (48,527
                Gjpd
                Cdn
      $7.89 per gj
                January
      1 - December 31(4,089
                Gjpd
                Participating
      Swap Cdn $7.62 per gj (31.3% below the ceiling price)
                January
      1 - November 30Foreign
      Exchange
                
                
                Sell
      US $4,721,469 per month @1.1101 (5)
                January
      1 - December 31Sell
      US $582,821 per month @1.0159 (5)
                January
      1 - August 31Sell
      US $1,407,419 per month @0.9781 (5)
                July
      1 - August 31Sell
      US $587,903 per month @1.0165 (5)
                July
      1 - November 30Sell
      US $2,254,103 per month @0.9577 (5)
                September
      1 - October 31Sell
      US $1,750,992 per month @1.0176 (5)
                September
      1 - November 30
 
 97
 Midstream,
      cont'd.Year
                Product
                (Buy)Sell
                Terms
                Effective
      Period2011
                Crude
      Oil
                5,389
                Bpd
                Cdn
      $71.68 per bbl
                January
      1 - December 31250
                Bpd
                Participating
      Swap US $63.00 per bbl (64% above the floor price)
                January
      1 - December 31500
                Bpd
                Costless
      Collar US $65.00 floor, US $75.00 ceiling
                January
      1 - June 302,000
                Bpd
                Costless
      Collar US $58.50 floor, US $72.69 ceiling
                July
      1 - September 30Natural
      Gas
                (37,595)
      Gjpd
                Cdn
      $7.31 per gj
                January
      1 - December 31Foreign
      Exchange
                
                
                Sell
      US $980,417 per month @1.0805 (5)
                January
      1 - June 30Sell
      US $3,587,999 per month @1.0931 (5)
                July
      1 - September 30Sell
      US $479,063 per month @0.9725 (5)
                January
      1 - December 312012
                Crude
      Oil
                3,647
                Bpd
                Cdn
      $72.95 per bbl
                January
      1 - December 311,141
                Bpd
                Participating
      Swap US $66.67 per bbl (59% above the floor price)
                April
      1 - December 31250
                Bpd
                Participating
      Swap Cdn $71.50 per bbl (50% above the floor price)
                October
      1 - December 31Natural
      Gas
                (25,787)
      Gjpd
                Cdn
      $7.23 per gj
                January
      1 - December 31Foreign
      Exchange
                
                
                Sell
      US $1,437,986 per month @0.9657 (5)
                July
      1 - December 31Sell
      US $976,436 per month @0.9413 (5)
                April
      1 - October 31Sell
      US $1,634,227 per month @0.9832 (5)
                October
      1 - December 312013
                Crude
      Oil
                250
                Bpd
                Cdn
      $75.32 per bbl
                January
      1 - January 31750
                Bpd
                Participating
      Swap US $70.92 per bbl (50.6% above the floor price)
                January
      1 - January 31250
                Bpd
                Participating
      Swap Cdn $71.50 per bbl (50% above the floor price)
                January
      1 - January 31Natural
      Gas
                (7,025)
      Gjpd
                Cdn
      $7.19 per gj
                January
      1 - January 31Foreign
      Exchange
                
                
                Sell
      US $1,651,990 per month @0.9832 (5)
                January
      1 - January 31CorporateYear
                Product
                (Buy)Sell
                Terms
                Effective
      Period2008
                Foreign
      Exchange
                
                
                Sell
      US $9,000,000 @.9701 (5.1)
                January
      25Sell
      US $3,000,000 @1.0105 (5.1)
                February
      25Interest
      Rate
                
                
                Pay
      Fixed rate of 4.8852% - Receive 3M CAD BA on Cdn $50MM Notional (11)
                January
      1 - July 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) Conversion
of Crude Oil BTU positions to liquids.
 (5) US dollar
contracts settled against Bank of Canada noon rate average.
 (5.1) US dollar cashflows sold
forward.
 (6) Propane
contracts are settled against Belvieu C3 TET.
 (7) Normal
Butane contracts are settled against Belvieu NC4 NON-TET.
 (8) ISO
Butane contracts are settled against Belvieu IC4 NON-TET.
 (9) Midstream
inventory price stabilization contracts.
 (10) Natural
Gas contracts are settled against Natural Gas-Michcon Citygate Inside
FERC.
 (11) Settles
quarterly against 3M CAD BA interest rate.
 (12) Power
contracts are settled monthly against the average hourly price of electricity as
published by the AESO in $/MWh.
 
 14.
Cash reserve for future site reclamation
 
 Provident
established a cash reserve effective May 1, 2001 for future site reclamation
expenditures relating to its Canadian oil and gas production. In accordance with
the royalty agreement, Provident funds the reserve by paying $0.30 per barrel of
oil equivalent produced on a 6:1 basis into a segregated cash account. Actual
expenditures incurred are then funded from the cash in this account. The cash
reserve was depleted in 2006 as actual expenditures exceeded contributions to
the reserve.
 
 98
  
 15.
Commitments
 
 Provident
has office lease commitments that extend through June 2022.  Future
minimum lease payments for the following five years are: 2008 - $8.6 million;
2009 - $10.6 million; 2010 - $10.5 million; 2011 - $10.4 million; and 2012
-$10.2 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: 2008 – $6.6 million; 2009 – $5.4 million; 2010 – $3.9
million; 2011 – $2.7 million, and 2012 – $1.3 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: 2008 - $4.3 million; 2009 - $4.0 million; 2010 - $3.8 million; 2011 –
$4.1 million and 2012 - $4.3 million.
  In
relation to the United States oil and natural gas production segment,
Provident’s U.S. subsidiaries have performance obligations that are secured, in
whole or in part, by surety bonds. These obligations primarily cover
self-insurance and other programs where governmental organizations require such
support.  These surety bonds are issued by financial institutions and
are required to be reimbursed by Provident’s U.S. subsidiaries if drawn upon. At
December 31, 2007, Provident’s U.S. subsidiaries had obtained various surety
bonds for U.S. $14.3 million (2006 – U.S. $4.9 million).
  In
relation to the United States oil and natural gas production segment, Provident
leases certain property and equipment under operating leases. Future minimum
lease payments for the following five years are as follows: 2008 – U.S. $0.9
million; 2009 – U.S. $0.8 million; 2010 – U.S. $0.7 million; 2011 – U.S. $0.7
million and 2012 – U.S. $0.7 million.
 
 16.
Subsequent event
 
 In
February 2008, the Trust announced that it has retained Morgan Stanley as
financial advisor in connection with a strategic review process with the
objective of selling the operations that comprise the United States oil and
natural gas production (USOGP) segment. USOGP includes the Trust’s interest in
the MLP, the related general partner interest, as well as the Trust’s interest
in BreitBurn Energy Company L.P.
  As at
December 31, 2007 the Trust owned approximately 22 percent of the MLP and
approximately 96 percent of BreitBurn Energy Company L.P.  Pursuant to
the announcement, the Trust will account for USOGP as discontinued operations
beginning in the first quarter of 2008.
 
 17.
Segmented information
 
 The
Trust’s business activities are conducted through three business segments:
Canadian oil and natural gas production (COGP), United States oil and natural
gas production (USOGP) and Midstream.
  Oil and
natural gas production in Canada and the United States includes exploitation,
development and production of crude oil and natural gas
reserves.  Midstream includes processing, extraction, transportation,
loading and storage of natural gas liquids, and marketing of natural gas
liquids.
  Geographically
the Trust operates in Canada and the USA in the oil and gas production business
segment.  The geographic components have been presented for the oil
and natural gas business as well as the Midstream business that operates in both
Canada and the USA.
  99
 
 Year
      ended December 31, 2007Canadian
      Oil
                
                
                U.S.
      Oil and
                
                
                Total
      Oil andand
      Natural Gas
                
                
                Natural
      Gas
                
                
                Natural
      GasProduction
                
                
                Production
                
                
                
                Production
                
                Midstream
      (1)
                
                
                TotalRevenueGross
      production revenue
                
                $
                454,179
                
                
                $
                278,414
                
                
                $
                732,593
                
                
                $
                -
                
                
                $
                732,593Royalties
                
                
                (87,046
                )
                
                
                (31,654
                )
                
                
                (118,700
                )
                
                
                -
                
                
                
                (118,700
                )Product
      sales and service revenue
                
                
                -
                
                
                
                -
                
                
                
                -
                
                
                
                1,958,372
                
                
                
                1,958,372Realized
      gain (loss) on financial derivativeinstruments
                
                
                1,728
                
                
                
                (7,959
                )
                
                
                (6,231
                )
                
                
                (74,474
                )
                
                
                (80,705
                )368,861
                
                
                
                238,801
                
                
                
                607,662
                
                
                
                1,883,898
                
                
                
                2,491,560ExpensesCost
      of goods sold
                
                
                -
                
                
                
                11,143
                
                
                
                11,143
                
                
                
                1,594,639
                
                
                
                1,605,782Production,
      operating and maintenance
                
                
                112,387
                
                
                
                81,699
                
                
                
                194,086
                
                
                
                14,094
                
                
                
                208,180Transportation
                
                
                8,193
                
                
                
                3,102
                
                
                
                11,295
                
                
                
                16,825
                
                
                
                28,120Foreign
      exchange (gain) loss and other
                
                
                (573
                )
                
                
                -
                
                
                
                (573
                )
                
                
                3,996
                
                
                
                3,423General
      and administrative
                
                
                27,102
                
                
                
                45,188
                
                
                
                72,290
                
                
                
                28,669
                
                
                
                100,959147,109
                
                
                
                141,132
                
                
                
                288,241
                
                
                
                1,658,223
                
                
                
                1,946,464Earnings
      before interest, taxes, depletion,depreciation,
      accretion and other non-cash items
                
                
                221,752
                
                
                
                97,669
                
                
                
                319,421
                
                
                
                225,675
                
                
                
                545,096Other
      revenueUnrealized
      loss on financial derivative
                
                
                (21,324
                )
                
                
                (110,040
                )
                
                
                (131,364
                )
                
                
                (192,920
                )
                
                
                (324,284
                )Other
      expensesDepletion,
      depreciation and accretion
                
                
                256,723
                
                
                
                50,253
                
                
                
                306,976
                
                
                
                44,388
                
                
                
                351,364Interest
      on bank debt
                
                
                11,055
                
                
                
                7,439
                
                
                
                18,494
                
                
                
                33,166
                
                
                
                51,660Interest
      and accretion on convertible debentures
                
                
                3,672
                
                
                
                10,660
                
                
                
                14,332
                
                
                
                11,015
                
                
                
                25,347Amortization
      of deferred financing charges
                
                
                -
                
                
                
                -
                
                
                
                -
                
                
                
                -
                
                
                
                -Unrealized
      foreign exchange loss and other
                
                
                779
                
                
                
                2,593
                
                
                
                3,372
                
                
                
                -
                
                
                
                3,372Dilution
      gain
                
                
                -
                
                
                
                (260,324
                )
                
                
                (260,324
                )
                
                
                -
                
                
                
                (260,324
                )Non-cash
      unit based compensation
                
                
                3,698
                
                
                
                5,950
                
                
                
                9,648
                
                
                
                4,366
                
                
                
                14,014Internal
      management charge
                
                
                (1,482
                )
                
                
                1,482
                
                
                
                -
                
                
                
                -
                
                
                
                -Capital
      tax expense
                
                
                3,762
                
                
                
                -
                
                
                
                3,762
                
                
                
                -
                
                
                
                3,762Current
      and withholding tax (recovery) expense
                
                
                (254
                )
                
                
                10
                
                
                
                (244
                )
                
                
                6,606
                
                
                
                6,362Future
      income tax expense (recovery) (2)
                
                
                (122,590
                )
                
                
                58,843
                
                
                
                (63,747
                )
                
                
                94,234
                
                
                
                30,487155,363
                
                
                
                (123,094
                )
                
                
                32,269
                
                
                
                193,775
                
                
                
                226,044Non-controlling
      interest - USOGP
                
                
                -
                
                
                
                (35,666
                )
                
                
                (35,666
                )
                
                
                -
                
                
                
                (35,666
                )Non-controlling
      interest - exchangeables
                
                
                -
                
                
                
                -
                
                
                
                -
                
                
                
                -
                
                
                
                -Net
      income (loss) for the period
                
                $
                45,065
                
                
                $
                146,389
                
                
                $
                191,454
                
                
                $
                (161,020
                )
                
                $
                30,434
 
 (1)
                Included
      in the Midstream segment is product sales and service revenue of $297.8
      million associated with U.S.
operations.
 (2)
                Future
      income tax expense (recovery) includes a charge of $88.4 million relating
      to the enactment of Bill C-52, Budget Implementation Act 2007 by the
      Canadian government (see note 12).
  100
 As
      at and for the year ended December 31, 2007Canadian
      Oil
                
                
                U.S.
      Oil and
                
                
                Total
      Oil andand
      Natural
                
                
                Natural
      Gas
                
                
                Natural
      GasGas
      Production
                
                
                Production
                
                
                Production
                
                
                Midstream
                
                
                TotalSelected
      balance sheet itemsCapital
      assetsProperty,
      plant and equipment net
                
                $
                1,773,209
                
                
                $
                2,008,549
                
                
                $
                3,781,758
                
                
                $
                737,062
                
                
                $
                4,518,820Intangible
      assets
                
                
                -
                
                
                
                3,763
                
                
                
                3,763
                
                
                
                171,793
                
                
                
                175,556Goodwill
                
                
                416,890
                
                
                
                -
                
                
                
                416,890
                
                
                
                100,409
                
                
                
                517,299Capital
      expendituresCapital
      Expenditures
                
                
                146,209
                
                
                
                69,009
                
                
                
                215,218
                
                
                
                31,904
                
                
                
                247,122Corporate
      acquisitions
                
                
                469,795
                
                
                
                -
                
                
                
                469,795
                
                
                
                -
                
                
                
                469,795Oil
      and gas property acquisitions, net
                
                
                13,050
                
                
                
                1,015,803
                
                
                
                1,028,853
                
                
                
                -
                
                
                
                1,028,853Goodwill
      additions
                
                
                85,946
                
                
                
                -
                
                
                
                85,946
                
                
                
                -
                
                
                
                85,946Working
      capitalAccounts
      receivable
                
                
                75,292
                
                
                
                79,457
                
                
                
                154,749
                
                
                
                262,813
                
                
                
                417,562Petroleum
      product inventor y
                
                
                -
                
                
                
                5,636
                
                
                
                5,636
                
                
                
                84,638
                
                
                
                90,274Accounts
      payable and accrued liabilities
                
                
                132,452
                
                
                
                77,442
                
                
                
                209,894
                
                
                
                214,574
                
                
                
                424,468Long-term
      debt - revolving term creditfacilities
                
                
                230,999
                
                
                
                368,836
                
                
                
                599,835
                
                
                
                692,997
                
                
                
                1,292,832Long-term
      debt - convertible debentures
                
                
                35,129
                
                
                
                115,925
                
                
                
                151,054
                
                
                
                105,386
                
                
                
                256,440Financial
      derivative instruments
                
                $
                13,559
                
                
                $
                102,859
                
                
                $
                116,418
                
                
                $
                261,587
                
                
                $
                378,005
  101
 Year
      ended December 31, 2006Canadian
      Oil
                
                
                U.S.
      Oil and
                
                
                Total
      Oil andand
      Natural
                
                
                Natural
      Gas
                
                
                Natural
      GasGas
      Production
                
                
                Production
                
                
                Production
                
                
                Midstream
      (1)
                
                
                TotalRevenueGross
      production revenue
                
                $
                402,095
                
                
                $
                176,160
                
                
                $
                578,255
                
                
                $
                -
                
                
                $
                578,255Royalties
                
                
                (81,225
                )
                
                
                (17,315
                )
                
                
                (98,540
                )
                
                
                -
                
                
                
                (98,540
                )Product
      sales and service revenue
                
                
                -
                
                
                
                -
                
                
                
                -
                
                
                
                1,764,392
                
                
                
                1,764,392Realized
      gain (loss) on financial derivativeinstruments
                
                
                4,371
                
                
                
                (2,505
                )
                
                
                1,866
                
                
                
                (15,406
                )
                
                
                (13,540
                )325,241
                
                
                
                156,340
                
                
                
                481,581
                
                
                
                1,748,986
                
                
                
                2,230,567ExpensesCost
      of goods sold
                
                
                -
                
                
                
                -
                
                
                
                -
                
                
                
                1,471,171
                
                
                
                1,471,171Production,
      operating and maintenance
                
                
                97,626
                
                
                
                52,008
                
                
                
                149,634
                
                
                
                22,619
                
                
                
                172,253Transportation
                
                
                5,114
                
                
                
                -
                
                
                
                5,114
                
                
                
                14,672
                
                
                
                19,786Foreign
      exchange gain and other
                
                
                (9
                )
                
                
                -
                
                
                
                (9
                )
                
                
                (2,728
                )
                
                
                (2,737
                )Cash
      general and administrative
                
                
                24,065
                
                
                
                26,519
                
                
                
                50,584
                
                
                
                23,621
                
                
                
                74,205126,796
                
                
                
                78,527
                
                
                
                205,323
                
                
                
                1,529,355
                
                
                
                1,734,678Earnings
      before interest, taxes, depletion,depreciation,
      accretion and other non-cash items
                
                
                198,445
                
                
                
                77,813
                
                
                
                276,258
                
                
                
                219,631
                
                
                
                495,889Other
      revenueUnrealized
      gain (loss) on financial derivativeinstruments
                
                
                17,299
                
                
                
                7,735
                
                
                
                25,034
                
                
                
                (68,348
                )
                
                
                (43,314
                )Other
      expensesDepletion,
      depreciation and accretion
                
                
                168,953
                
                
                
                31,058
                
                
                
                200,011
                
                
                
                49,128
                
                
                
                249,139Interest
      on bank debt
                
                
                10,082
                
                
                
                4,861
                
                
                
                14,943
                
                
                
                19,723
                
                
                
                34,666Interest
      and accretion on convertible debentures
                
                
                5,746
                
                
                
                5,828
                
                
                
                11,574
                
                
                
                12,345
                
                
                
                23,919Amortization
      of deferred financing charges
                
                
                956
                
                
                
                786
                
                
                
                1,742
                
                
                
                2,112
                
                
                
                3,854Unrealized
      foreign exchange loss and other
                
                
                -
                
                
                
                -
                
                
                
                -
                
                
                
                418
                
                
                
                418Dilution
      gain
                
                
                -
                
                
                
                -
                
                
                
                -
                
                
                
                -
                
                
                
                -Non-cash
      unit based compensation
                
                
                4,320
                
                
                
                12,476
                
                
                
                16,796
                
                
                
                6,287
                
                
                
                23,083Internal
      management charge
                
                
                (1,280
                )
                
                
                1,280
                
                
                
                -
                
                
                
                -
                
                
                
                -Capital
      tax expense
                
                
                1,314
                
                
                
                -
                
                
                
                1,314
                
                
                
                -
                
                
                
                1,314Current
      and withholding tax expense
                
                
                (2,124
                )
                
                
                3,332
                
                
                
                1,208
                
                
                
                4,621
                
                
                
                5,829Future
      income tax expense (recovery)
                
                
                (56,161
                )
                
                
                20,297
                
                
                
                (35,864
                )
                
                
                1,548
                
                
                
                (34,316
                )131,806
                
                
                
                79,918
                
                
                
                211,724
                
                
                
                96,182
                
                
                
                307,906Non-controlling
      interest - USOGP
                
                
                -
                
                
                
                2,995
                
                
                
                2,995
                
                
                
                -
                
                
                
                2,995Non-controlling
      interest - exchangeables
                
                
                485
                
                
                
                37
                
                
                
                522
                
                
                
                232
                
                
                
                754Net
      income for the period
                
                $
                83,453
                
                
                $
                2,598
                
                
                $
                86,051
                
                
                $
                54,869
                
                
                $
                140,920(1)Included in the Midstream segment is product sales and service
      revenue of $332.9 million associated with U.S. operations.
 
 102
 As
      at and for the year ended December 31, 2006Canadian
      Oil
                
                
                U.S.
      Oil and
                
                
                Total
      Oil andand
      Natural
                
                
                Natural
      Gas
                
                
                Natural
      GasGas
      Production
                
                
                Production
                
                
                Production
                
                
                Midstream
                
                
                TotalSelected
      balance sheet itemsCapital
      assetsProperty,
      plant and equipment net
                
                $
                1,211,112
                
                
                $
                380,451
                
                
                $
                1,591,563
                
                
                $
                741,974
                
                
                $
                2,333,537Intangible
      assets
                
                
                -
                
                
                
                -
                
                
                
                -
                
                
                
                193,592
                
                
                
                193,592Goodwill
                
                
                330,944
                
                
                
                -
                
                
                
                330,944
                
                
                
                100,409
                
                
                
                431,353Capital
      expendituresCapital
      expenditures
                
                
                70,088
                
                
                
                54,337
                
                
                
                124,425
                
                
                
                66,008
                
                
                
                190,433Corporate
      acquisitions
                
                
                -
                
                
                
                -
                
                
                
                -
                
                
                
                1,036
                
                
                
                1,036Oil
      and gas property acquisitions, net
                
                
                483,633
                
                
                
                (2,008
                )
                
                
                481,625
                
                
                
                -
                
                
                
                481,625Goodwill
      additions
                
                
                -
                
                
                
                -
                
                
                
                -
                
                
                
                2,285
                
                
                
                2,285Working
      capitalAccounts
      receivable
                
                
                58,250
                
                
                
                24,744
                
                
                
                82,994
                
                
                
                187,141
                
                
                
                270,135Petroleum
      product inventor y
                
                
                -
                
                
                
                -
                
                
                
                -
                
                
                
                85,868
                
                
                
                85,868Accounts
      payable and accrued liabilities
                
                
                86,305
                
                
                
                52,626
                
                
                
                138,931
                
                
                
                156,072
                
                
                
                295,003Long-term
      debt - revolving term creditfacilities
                
                
                172,980
                
                
                
                11,072
                
                
                
                184,052
                
                
                
                518,941
                
                
                
                702,993Long-term
      debt - convertible debentures
                
                
                44,553
                
                
                
                117,470
                
                
                
                162,023
                
                
                
                123,769
                
                
                
                285,792Financial
      derivative instruments(asset)
      liability
                
                $
                (7,520
                )
                
                $
                (8,417
                )
                
                $
                (15,937
                )
                
                $
                68,795
                
                
                
                52,858
  103
 18.
Related party transactions
 
 Included
in accounts receivable as at December 31, 2007 is $32.8 million with related
parties. Of this amount, $22.5 million represents a net receivable from
Quicksilver, reflecting cash collections made on behalf of a subsidiary of the
Trust in connection with the acquisition of assets from Quicksilver in the
fourth quarter of 2007, net of advances. Quicksilver owns approximately 32
percent of the outstanding units of the MLP, a subsidiary of the Trust. The
remaining $10.3 million relates to sales of crude oil by a subsidiary of the
trust to a buyer whose Chairman of the Board and Chief Executive Officer is also
a director of the general partner of the subsidiary of the Trust.
 
 19.
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)
                
                2007
                
                
                2006Net
      income as reported
                
                $
                30,434
                
                
                $
                140,920AdjustmentsDepletion,
      depreciation and accretion (a)
                
                
                72,485
                
                
                
                12,146Depletion,
      depreciation and accretion other (a)
                
                
                (181,551
                )
                
                
                (382,230
                )General
      and administrative (d)
                
                
                483
                
                
                
                (483
                )Future
      income tax recovery (a) (b)
                
                
                23,625
                
                
                
                110,898Accretion
      on convertible debentures (e)
                
                
                2,802
                
                
                
                2,694Non-controlling
      interest
                
                
                (2,895
                )
                
                
                754Net
      loss – U.S. GAAP
                
                $
                (54,617
                )
                
                $
                (115,301
                )Other
      comprehensive (loss) income
                
                
                (26,000
                )
                
                
                (509
                )Comprehensive
      income (loss)
                
                
                (80,617
                )
                
                
                (115,810
                )Net
      loss per unit - basic and diluted
                
                $
                (0.24
                )
                
                $
                (0.59
                )
  Condensed
      Consolidated Balance SheetAs
      at December 31, (Cdn$ 000s)
                
                2007
                
                
                
                
                
                2006Canadian
                
                
                
                
                
                CanadianGAAP
                
                
                U.S.
      GAAP
                
                
                GAAP
                
                
                U.S.
      GAAPAssetsDeferred
      financing charges (e)
                
                $
                -
                
                
                $
                14,809
                
                
                $
                12,351
                
                
                $
                12,351Property,
      plant and equipment (a)
                
                
                4,518,820
                
                
                
                3,983,181
                
                
                
                2,333,537
                
                
                
                1,906,964Liabilities
      and unitholders’ equityCurrent
      portion of convertible debentures (e)
                
                
                19,198
                
                
                
                19,931
                
                
                
                -
                
                
                
                -Long-term
      debt - revolving term credit facilities (e)
                
                
                1,292,832
                
                
                
                1,300,645
                
                
                
                702,993
                
                
                
                702,993Long-term
      debt - convertible debentures (e)
                
                
                256,440
                
                
                
                274,113
                
                
                
                285,792
                
                
                
                300,110Other
      long-term liabilities (d)
                
                
                20,759
                
                
                
                20,759
                
                
                
                16,305
                
                
                
                16,788Future
      income taxes (a) (b)
                
                
                450,000
                
                
                
                296,597
                
                
                
                309,006
                
                
                
                180,122Non-controlling
      interests
                
                
                1,100,136
                
                
                
                1,103,031
                
                
                
                81,111
                
                
                
                81,111Units
      subject to redemption (f)
                
                
                -
                
                
                
                2,308,273
                
                
                
                -
                
                
                
                2,317,196Convertible
      debentures equity component (e)
                
                
                18,213
                
                
                
                -
                
                
                
                18,522
                
                
                
                -Unitholders’
      contributions (f)
                
                
                2,750,374
                
                
                
                -
                
                
                
                2,254,048
                
                
                
                -Accumulated
      other comprehensive (loss) income
                
                
                (69,188
                )
                
                
                (69,188
                )
                
                
                (42,294
                )
                
                
                (43,187
                )Accumulated
      income (loss)
                
                
                268,642
                
                
                
                (927,762
                )
                
                
                238,208
                
                
                
                (1,044,840
                )Accumulated
      cash distributions (f)
                
                
                (1,260,177
                )
                
                
                -
                
                
                
                (926,825
                )
                
                
                -
 
 (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
  104
 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 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 2007 of $181.6 million (2006 – $382.2
      million) and a related future income tax recovery of $52.2 million (2006 -
      $114.7 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.
  (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. Changes in redemption value in the period
      (2007 - $505.1 million; 2006 - $188.6 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.
 
 Recent
U.S. Accounting Pronouncements
  105
 
 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 application of this
standard will impact how the Trust’s balance sheet and statement of operations
are presented.
 
 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 Trust does not expect the adoption of this statement to
have a material impact on its 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 Trust is currently evaluating the
effect that this statement might have on the Trust’s financial
statements.
 
   106
 
 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, 2007, 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, 2007, 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 “Auditors’ Report” that accompanies the registrant’s
      Consolidated Financial Statements for the fiscal year ended December 31,
      2007, 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, 2007, 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.
 
 
 
 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 is “independent” as
that term in defined in the rules of the New York Stock Exchange.
 
 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 tabular disclosure is included under the heading Audit
Committee Information—External Auditor Service Feesin the Renewal Annual
Information Form, filed as part of this Annual Report on Form 40-F.
 
 Audit
Fees.
 
 Audit
fees consist of fees for the audit of the registrant’s annual financial
statements or services that are normally provided in connection with statutory
and regulatory filings or engagements.
  Fees for
audit services totaled approximately $2.9 million in 2007 and approximately $2.7
million in 2006, including fees associated with the annual audit, the reviews of
the Trust’s quarterly reports, statutory audits and regulatory filings. These
fees include approximately $1.7 million in 2007 and $1.5 million in 2006
directly related to U.S. operations.
 
 Audit-Related
Fees.
 
 Audit-related
fees consist of fees for assurance and related services that are reasonably
related to the performance of the audit or review of the registrant’s financial
statements
  
 and are
not reported as Audit Fees. Fees for audit-related services totaled
approximately $0.6 million in 2007 and approximately $1.2 million in 2006. Audit
related services include consultations concerning documents filed with respect
to audits in connection with proposed or completed acquisitions and for 2007
included work related to BreitBurn Energy Partners L.P.
 
 Tax
Fees.
 
 Tax fees
consist of fees for tax compliance services, tax advice and tax planning. During
fiscal 2007 and 2006, the services provided in this category included assistance
and advice in relation to the preparation of corporate tax returns. Fees for tax
services totaled approximately $0.7 million in 2007 and approximately $1.2
million in 2006.
 
 All Other
Fees.
 
 Fees for
all other services totaled approximately $0.2 million in 2007 for miscellaneous
consulting services.
 
 Pre-Approval
Policies and Procedures.
 
 (a)
                  All
      proposed services or the fees payable in connection with such services
      that have not already been pre-approved must be pre-approved by either the
      audit committee or pursuant to Delegated Authority (as defined below).
      Subject to the next paragraph, the audit committee has delegated authority
      to the chairman of the audit committee to pre-approve the provision of
      permitted services by PricewaterhouseCoopers LLP and not otherwise
      pre-approved by the full audit committee, including the fees and terms of
      the proposed services ("Delegated Authority"). All pre-approvals granted
      pursuant to Delegated Authority must be presented by the chairman to the
      full audit committee at its next
meeting.
  The
      fees payable in connection with any particular service to be provided by
      PricewaterhouseCoopers LLP that has been pre-approved pursuant to
      Delegated Authority may not exceed Cdn$100,000. Amounts exceeding
      Cdn$100,000 must be pre-approved by the full audit
    committee.
  Prohibited
      services may not be pre-approved by the audit committee or pursuant to
      Delegated Authority.
  (b)
                  Of
      the fees reported in this Annual Report on Form 40-F under the heading
      “Principal Accountant Fees and Services” (including the disclosure
      reported under the heading Audit
      Committee Information—External Auditor Service Feesin the Renewal
      Annual Information Form filed as part of this Annual Report on Form 40-F),
      nil of the fees billed by PricewaterhouseCoopers LLP were approved by the
      audit committee of the registrant pursuant to the de
      minimisexception provided by Section (c)(7)(i)(C) of Rule 2-01 of
      Regulation S-X.
  
 Off-Balance
Sheet Arrangements.
 
 The
registrant does not have any off-balance sheet financing arrangements that have
or are reasonably likely to have an effect on its results of operations or
financial condition.
 
 Tabular
      Disclosure of Contractual Obligations.Consolidated
                  
                  
                  
                  
                  
                  
                  
                  Payment
      Due By Period$Millions
                  
                  Total
                  
                  
                  Less
      than
                  
                  
                  
                  1–
      3
                  
                  
                  
                  3–
      5
                  
                  
                  More
      than1
      year
                  
                  
                  
                  years
                  
                  
                  years
                  
                  
                  5
      yearsLong-term
      debt – revolving term credit facilities(1)
                  
                  $
                  1,483.4
                  
                  
                  $
                  76.1
                  
                  
                  $
                  1,407.3
                  
                  
                  $
                  -
                  
                  
                  $
                  -Long-term
      debt – convertible debentures
                  
                  
                  343.0
                  
                  
                  
                  39.1
                  
                  
                  
                  58.0
                  
                  
                  
                  245.9
                  
                  
                  
                  -Operating
      lease obligations
                  
                  
                  224.7
                  
                  
                  
                  20.4
                  
                  
                  
                  39.6
                  
                  
                  
                  34.4
                  
                  
                  
                  130.3Total
                  
                  $
                  2,051.1
                  
                  
                  $
                  135.6
                  
                  
                  $
                  1,504.9
                  
                  
                  $
                  280.3
                  
                  
                  $
                  130.3
 
 1) The
terms of the Canadian credit facility have a revolving three year period
expiring on May 30, 2010. Provident 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 Provident 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. Management intends to extend the revolving
period beyond the current maturity date.
 
 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
  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 Securities
Exchange Act of 1934. Provident's Board of Directors has not adopted the
director independence standards contained in Section 303A.02 of the NYSE's
Listed Company Manual.
  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 Steet
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 2006 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 – 2 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).
 
 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
relevant registration statement.
 
 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 27, 2008.
   PROVIDENT
      ENERGY TRUST
                      By:
      Provident Energy Ltd.By:
                    /s/ Thomas
      W. BuchananName:Thomas
      W. BuchananTitle:President
      and Chief Executive Officer
 EXHIBIT
INDEX
 
 Exhibit
Description
 
 99.1
                  Certification of Chief Executive Officer pursuant to
      Rule 13a-14(a) or 15d-14 of the Securities Exchange Act of
      1934
  99.2
                  Certification of Chief Financial Officer pursuant to
      Rule 13a-14(a) or 15d-14 of the Securities Exchange Act of
      1934
  99.3
                  Certification of Chief Executive Officer pursuant to 18
      U.S.C. Section 1350
  99.4
                  Certification of Chief Financial Officer pursuant to 18
      U.S.C. Section 1350
  99.5
                  Consent of PricewaterhouseCoopers
  LLP
  99.6
                  Consent of McDaniel & Associates Consultants
      Ltd.
  99.7
                  Consent of Netherland, Sewell & Associates
      Inc.
  99.8
                  Consent of AJM Petroleum
  Consultants
  99.9
                  Consent of Data & Consulting Services Division of
      Schlumberger Technology
Corporation