---

U.S. SECURITIES AND EXCHANGE COMMISSION

FORM 40-F

(Check One)

[

For the fiscal year ended December 31, 2003

Commission file number 1-15196

PROVIDENT ENERGY TRUST

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


Suite 700, 112-4th Avenue S.W., Calgary, Alberta, Canada T2P
0H3 (403) 296-2233 
(Address and Telephone Number of Registrant's Principal Executive Offices)

Torys LLP, 237 Park Avenue, New York, NY 10017 (212) 880-6000

(Name, Address (Including Zip Code) and Telephone Number 
(Including Area Code) of Agent For Service in the United States)

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

Title of each class
      Name of each exchange on which registeredTrust Units
      American 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, 2003: 82,824,688

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 ___           
No X

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.

Yes X         
No___

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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, 2003;(b)
>       Management's Discussion and Analysis of Financial Condition andResults of Operations for the fiscal year ended December 31, 2003; and(c)
>       Consolidated Financial Statements for the fiscal year ended December 31,2003(Note 21 to the Consolidated Financial
>       Statements relates to UnitedStates Accounting Principles and Reporting (U.S. GAAP)).

---











RENEWAL ANNUAL INFORMATION FORM

For the year ended December 31, 2003







April 23, 2004





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TABLE OF CONTENTS
Page
    
    PageGLOSSARY OF TERMS
    1
    Principal Properties
    36ABBREVIATIONS, TERMS
    AND CONVERSIONS
    4
    Reserves and Future Net Revenue
    38NOTE REGARDING FORWARD
    LOOKING
    STATEMENTS
    5
    MIDSTREAM NGL
    PROCESSING OPERATIONSGeneral
    4545INCORPORATION AND
    STRUCTURE
    7
    NGL Extraction
    46The Trust
    7
    NGL Fractionation
    46Provident
    7
    NGL Transportation
    46Provident Holdings Trust
    7
    NGL Storage
    47Provident Acquisitions L.P
    7
    NGL Marketing
    47Provident Acquisitions Inc
    7
    Commercial Arrangements
    47INTERCORPORATE
    RELATIONSHIPS
    8
    SELECTED CONSOLIDATED
    FINANCIALINFORMATION CONCERNING
    THE TRUST,
    
    INFORMATION
    48PROVIDENT AND CERTAIN SUBSIDIARIES
    9
    MANAGEMENT'S DISCUSSION
    AND ANALYSIS
    49Provident Energy Trust
    9
    MARKET FOR SECURITIES
    49Provident Energy Ltd
    17
    DIRECTORS AND OFFICERS
    50Provident Holdings Trust and Provident
    
    INFORMATION CONCERNING
    THE OIL AND GASAcquisitions L.P
    20
    INDUSTRY
    57Provident Acquisitions Inc
    20
    Canadian Government Regulation
    57The Manager
    24
    Pricing and Marketing - Oil
    57GENERAL DEVELOPMENT OF
    THE BUSINESS OF
    
    Pricing and Marketing - Natural Gas
    58THE TRUST AND PROVIDENT
    25
    The North American Free Trade Agreement
    58SIGNIFICANT
    ACQUISITIONS
    28
    Provincial Royalties and Incentives
    58Founders Arrangement
    28
    Alberta
    59Maxx Arrangement
    28
    Environmental Regulation
    59Richland Arrangement
    29
    Exports from Canada
    59Southeast Alberta Property Acquisition
    30
    RISK FACTORS
    59Meota Takeover
    30
    Oil and Gas Production Risk Factors
    60Redwater Acquisition
    30
    Midstream NGL Asset Risk Factors
    62Proposed Acquisition of Viracocha Energy Inc
    32
    General Risk Factors
    65Proposed Acquisition of Olympia Energy Inc
    32
    INTERESTS OF MANAGEMENT
    AND OTHERS INCORPORATE STRATEGY AND
    RISK
    
    MATERIAL TRANSACTIONS
    68MANAGEMENT
    33
    TRANSFER AGENT AND
    REGISTRAR
    68General
    33
    INTERESTS OF EXPERTS
    68Commodity Price Risk Management Program
    33
    DOCUMENTS INCORPORATED
    BY REFERENCE
    69OIL AND NATURAL GAS
    OPERATIONS
    36
    ADDITIONAL INFORMATION
    69
SCHEDULE A -
    FINANCIAL STATEMENTS OF REDWATER NATURAL GAS LIQUIDS PROCESSING SYSTEM OFWILLIAMS ENERGY (CANADA), INC.SCHEDULE B -
    REPORT
    ON RESERVES DATA BY INDEPENDENT QUALIFIED RESERVES EVALUATOR ORAUDITORSCHEDULE C -
    REPORT
    OF MANAGEMENT AND DIRECTORS ON RESERVES DATA AND OTHERINFORMATION-i-

---



GLOSSARY OF TERMS

"ABCA" means the Business Corporations Act (Alberta), S.A.
1981, c. B-15, as amended, including the regulations promulgated thereunder;

"Acquired Properties" means the oil and gas properties
located in southeast Alberta acquired by the Trust effective May 1, 2002 from a
U.S. based exploration and production company pursuant to an agreement of
purchase and sale dated March 25, 2002;

"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);

"AMEX" means the American Stock Exchange;

"ARTC" means credits or rebates in respect of Crown
royalties, which are paid or credited by the Crown, including those paid or
credited under the Alberta Corporate Tax Act, which are commonly known as
"Alberta Royalty Tax Credits";

"Board of Directors" or "Board" means the board of directors of
Provident;

"Budget" means the Notice of Ways and Means Motion released as an
annex to the March 23, 2004 Canadian Federal Budget;

"8.75% Debentures" means the 8.75% convertible unsecured subordinated
debentures of the Trust;

"10.5% Debentures" means the 10.5% convertible unsecured subordinated
debentures of the Trust;

"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;

"Founders Arrangement" means the arrangement effective
March 6, 2001 under the ABCA involving, among other things, the exchange of the
common shares of Founders for notes, the exchange of the notes for Trust Units
and the amalgamation of Founders with Provident;

"Holdings Trust" means Provident Holdings Trust;

"McDaniel" means McDaniel & Associates Consultants Ltd., independent
oil and gas reservoir engineers of Calgary, Alberta;

"McDaniel Report" means the independent engineering evaluations of
Provident's oil, NGL and natural gas interests prepared by McDaniel dated April
2, 2004 effective December 31, 2003;

"Management Agreement" means the management agreement dated as of
March 6, 2001 among Provident, the Manager and the Trustee on behalf of the
Trust;

"Manager"means Provident Management Corporation, a corporation
incorporated under the ABCA;



- 1 -

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"Maxx" means Maxx Petroleum Ltd.;

"Maxx Arrangement" means the arrangement under the
ABCA involving, among other things, the exchange of the common shares of Maxx
for notes, the exchange of such notes for cash and/or Trust Units and the
amalgamation of Maxx with Provident;

"Meota" means Meota Resources Corp.;

"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 Canada;

"Non-Resident" means a non-resident of Canada for the purposes of the
Tax Act;

"Opal" means Opal Energy Inc.;

"Option Plan" means the trust unit option plan of the Trust providing
for the issuance of options to acquire Trust Units to employees, officers,
directors and consultants of the Trust;

"PAI" means Provident Acquisitions Inc.;

"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;

"Provident" means Provident Energy Ltd.;

"Provident LP" means Provident Acquisitions L.P.;

"Redwater Acquisition" means the September 30, 2003
acquisition by Provident of the Redwater natural gas liquids processing business
from Williams Canada for an aggregate purchase price of approximately $298.6
million (including costs associated with the acquisition), subject to certain
adjustments;

"Richland" means Richland Petroleum Corporation;

"Richland Arrangement" means the arrangement under the
ABCA involving, among other things, the exchange of the common shares of
Richland for notes, the exchange of such notes for Trust Units and the
amalgamation of Richland with Provident;

"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% 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% of the Trust Units represented at the meeting and voted on a poll upon such
resolution;

- 2 -

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"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 bodies corporate 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;

"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 which funds may from time to time be
invested; (d) the initial royalty granted to the Trust; (e) any Subsequent
Investment; (f) any proceeds of disposition of any of the foregoing property;
(g) the common shares of Founders and the initial notes of Provident held by the
Trust; and (h) all income, interest, profit, gains and accretions and additional
assets, rights and benefits of any kind or nature whatsoever arising directly or
indirectly from or in connection with or accruing to such foregoing property or
such proceeds of disposition;

"Trust Unit" means a unit of the Trust, each unit representing an
equal undivided beneficial interest therein;

"Unitholders" means the holders from time to time of the Trust Units;

"Unitholder Rights Plan" means the trust unitholders
rights plan adopted by the Trust pursuant to a trust unitholder rights plan
agreement dated March 6, 2001 between the Trust and Computershare Trust Company
of Canada;

"Trustee" means Computershare Trust Company of Canada or such other
trustee, from time to time, of the Trust;

- 3 -

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"TSX" means the Toronto Stock Exchange;

"Unitholder Rights Plan Agreement" means the agreement
dated March 6, 2001 between the Trust and Computershare Trust Company of Canada
pursuant to which the Trust adopted the Unitholder Rights Plan;

"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

"Williams Canada" means Williams Energy (Canada), Inc.

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
|----------------------------------------
|                                        
|Oil and Natural Gas Liquids             
|                                        
|bbls                                    
|mbbls                                   
|bpd                                     
|mmbbls                                  
|NGLs                                    
|STB                                     
|mstb                                    
|boed                                    
|                                        



|Other |                                                                                                                                                                                                                                                                                                                                | 
|----- | ------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------ | 
|      |                                                                                                                                                                                                                                                                                                                                | 
|boe   | 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.
|     
|     
|     
|mboe  | means
    thousand barrels of oil equivalent.                                                                                                                                                                                                                                                                                  | 
|WTI   | means
    West Texas Intermediate.                                                                                                                                                                                                                                                                                             | 
|API   | means the measure of
    the density or gravity of liquid petroleum products derived from a
    specific gravity.                                                                                                                                                                                                             
|     



| |                                                                                                                                                        
| | -------------------------------------------------------------------------------------------------------------------------------------------------------
| | CONVERSION                                                                                                                                             
| | The following
    table sets forth certain conversions between Standard Imperial Units and the
    International
    System of Units (or metric units).
| |                                                                                                                                                        
| | To Convert From                                                                                                                                        
| | mcf                                                                                                                                                    
| | cubic
    metres                                                                                                                                       
| | Bbls                                                                                                                                                   
| | cubic
    metres                                                                                                                                       
| | feet                                                                                                                                                   
| | metres                                                                                                                                                 

- 4 -

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| | To Convert From |  | To         |  | Multiply By
| | --------------- |  | ---------- |  | -----------
| | miles           |  | kilometres |  | 1.609      
| | kilometres      |  | miles      |  | 0.621      
| | acres           |  | hectares   |  | 0.405      
| | hectares        |  | acres      |  | 2.471      
| | gigajoules      |  | mmbtu      |  | 0.950      



For the purposes of this Annual Information Form all conversions of natural
gas to barrels of oil equivalent are on the basis of 6 mcf to 1 boe.

NOTE REGARDING FORWARD LOOKING STATEMENTS

This Annual Information Form and the documents incorporated
by reference herein contain forward-looking statements. These statements relate
to future events or the Trust's future performance. 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. These statements are only predictions. Actual events or
results may differ materially. In addition, this 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 these forward-looking statements, 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
Annual Information Form and the documents incorporated by reference herein
include, but are not limited to, statements with respect to:

- 

the Trust's acquisition
  strategy, the criteria to be considered in connection therewith and the
  benefits to be derived therefrom;

the goal to sustain or
  grow production and reserves through prudent management and acquisitions;

the emergence of
  accretive growth opportunities;

the objective to achieve
  a consistent level of monthly cash distributions;

the impact of Canadian
  governmental regulation on the Trust relative to other oil and gas companies
  or trusts of similar size;

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;

the impact of changes in
  oil and natural gas prices on cash flow after hedging;

the focus of capital
  expenditures on 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;

the development focus in
  the Lloydminster heavy oil area;

drilling plans;

the performance
  characteristics of the Midstream NGL Assets;

the growth opportunities
  associated with the natural gas midstream and NGL processing business; and

- 5 -

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the nature of
  contractual arrangements with third parties for the use of Midstream NGL
  Assets. 

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 statements
contained in this 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, including fluctuations in the price of crude oil, natural gas and
  natural gas liquids and conditions associated with the midstream NGL business;

uncertainties associated with estimating reserves;

royalties
  payable in respect of the Trust's oil and gas production;

governmental regulation 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 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 obtain industry partner and other third party consents and approvals, when
  required;

third
  party performance of obligations under contractual arrangements; and

the other
  factors set forth under "Risk Factors" in this Annual Information Form.

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. Readers are cautioned that the
foregoing list of factors is not exhaustive. The forward-looking statements
contained in this Annual Information Form and the documents incorporated by
reference herein are expressly qualified by this cautionary statement. Subject
to the Trust's obligations under applicable securities laws, the Trust is not
under any duty to update any of the forward-looking statements after the date of
this Annual Information Form to conform such statements to actual results or to
changes in the Trust's expectations.

- 6 -

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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 700, 112 - 4th Avenue S.W., Calgary, Alberta T2P 0H3. The registered
office of the Trust is 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 Energy Ltd. pursuant to a
plan of arrangement involving the Trust, Provident and Founders effective March
6, 2001. Provident subsequently amalgamated with Maxx Petroleum Ltd. effective
May 25, 2001 pursuant to a plan of arrangement involving the Trust, Provident
and Maxx. Provident was also amalgamated with Richland Petroleum Corporation
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, the Manager and the shareholders of the Manager
effective January 17, 2003. The head and principal offices of Provident are
located at 700, 112 - 4th Avenue S.W., Calgary, Alberta T2P 0H3. The registered
office of Provident is 3700, 400 - 3rd Avenue S.W., Calgary, Alberta T2P 4H2.
Provident owns all of the common shares of the following five subsidiaries:
Provident Acquisitions Inc., 611335 Alberta Ltd., 873798 Alberta Ltd., Terraquest Inc. and Coast Pacific RLP-97 Exploration Inc.

Provident Holdings Trust

Provident Holdings Trust is an open-end unincorporated
commercial trust governed by the laws 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% interest in the limited partnership,
Provident Acquisitions L.P. The head and principal offices of Holdings Trust are
located at 700, 112 - 4th Avenue S.W. Calgary, Alberta T2P 0H3. The registered
office of Holdings Trust is 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 LP was formed pursuant to a
limited partnership agreement dated April 19, 2002. The general partner of
Provident LP is Provident which holds a 1% interest in the partnership. Holdings
Trust is the limited partner of Provident LP with a 99% interest in the
partnership. The head and principal offices of Provident LP are located at 700,
112 - 4th Avenue S.W. Calgary, Alberta T2P 0H3. The registered office of
Provident LP is 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. PAI is the
beneficial owner of all of the shares of 101011500 Saskatchewan Ltd. and holds a
0.00001% interest in the Meota (2000) Partnership. 101011500 Saskatchewan Ltd.
holds the remaining interest in the Meota (2000) Partnership. The head and
principal offices of PAI are located at 700, 112 - 4th Avenue S.W., Calgary,
Alberta, T2P 0H3. The registered office of PAI is 3700, 400 - 3rd Avenue S.W.,
Calgary, Alberta, T2P 4H2.

- 7 -

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INTERCORPORATE RELATIONSHIPS

The following diagram describes the flow of cash from the oil
and gas properties and Midstream NGL Assets to the Trust and from the Trust to
the Unitholders. Reference should be made to the appropriate sections of this
Annual Information Form for a complete description of the structure of the
Trust.



Note:

(1) Portion of cash flow withheld to fund capital expenditures, reclamation
fund and debt repayment.

- 8 -

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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 Midstream NGL Assets. Cash flow from the petroleum and
natural gas properties flows from Provident, Provident LP and PAI 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 Midstream NGL
Assets flows from Provident to the Trust 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.

> 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 oil and natural gas properties 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 Midstream NGL Assets, 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

- 9 -

---



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.

> Special Voting Units

An unlimited number of Special Voting Units may be created
and issued pursuant to the Trust Indenture. Holders of Special Voting Units
shall not be entitled to any distributions of any nature whatsoever from
Provident and shall be entitled to such number of votes at meetings of holders
of Trust Units as may be prescribed by the board of directors of Provident in
the resolution authorizing the issuance of any Special Voting Units. Except for
the right to vote at meetings of the holders of Trust Units, the Special Voting
Units shall not confer upon the holders thereof any other rights. As of April
20, 2004, there were two Special Voting Units issued and outstanding.

> 10.5% Debentures

In April 2002, the Trust issued $64,410,000 aggregate
principal amount of convertible unsecured subordinated debentures. The 10.5%
Debentures mature on May 15, 2007 and bear interest at a rate of 10.5% per
annum, payable semi-annually in arrears on May 15 and November 15 in each year.
The 10.5% Debentures are convertible at the option of the holder into Trust
Units at any time prior to the earlier of May 15, 2007 and the business day
immediately preceding any date specified by the Trust for redemption at a
conversion price of $10.70 per Trust Unit, subject to adjustment in certain
circumstances. After May 15, 2005 and prior to maturity, the Trust may redeem
the 10.5% Debentures in whole or in part from time to time at a price of $1,050
per 10.5% Debenture from May 15, 2005 until May 15, 2006 and at a price of
$1,025 per 10.5% Debenture thereafter until maturity, in each case plus accrued
and unpaid interest. On redemption or maturity of the 10.5% Debentures, the
Trust may, subject to regulatory approval, elect to satisfy the redemption price
or principal amount by issuing Trust Units to the 10.5% Debenture holder. As of
April 20, 2004, there was $49,910,000 aggregate principal amount of 10.5%
Debentures outstanding.

> 8.75% Debentures

In September 2003, the Trust issued $75,000,000 aggregate
principal amount of convertible unsecured subordinated debentures. The 8.75%
Debentures mature on December 31, 2008 and bear interest at a rate of 8.75% per
annum, payable semi-annually in arrears on June 30 and December 31 in each year.
The 8.75% 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% Debentures in whole or in part from time to time at a price of $1,050
per 8.75% Debenture from January 1, 2007 until January 1, 2008 and at a price of
$1,025 per 8.75% Debenture thereafter until maturity, in each case plus accrued
and unpaid interest. On redemption or maturity of the 8.75% 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% Debenture holder. As of
April 20, 2004, there was $75,000,000 aggregate principal amount of 8.75%
Debentures outstanding.

> 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

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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% 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% of
the Trust Units; (b) a quorum of 50% 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 has implemented a trust unit option plan. Under the
Option Plan, options to purchase a maximum of 5,000,000 Trust Units may be
granted to employees, officers, directors and consultants to the Trust and its
subsidiaries. The Option Plan will be administered by Provident. Subject to
regulatory approval, the exercise price of an option will be determined at the
time of grant and is to be not less than the closing price of the Trust Units on
the TSX on the last day preceding the grant on which a trade of Trust Units
occurred on such exchange, subject to certain reductions in the exercise price
of an option in certain circumstances based upon the cash distributions made on
the Trust Units. The term of an option and vesting provisions are to be
determined at the time of grant and may vary as between individual grants of
options. However, the term of an option shall not be less than one year and not
more than ten years from the date of grant. Options are exercisable only during
the term of employment or service of an employee, consultant or officer or
during the period of service as a director or trustee. Provident shall determine
whether any or all of the options shall be exercisable for a period following
the date of termination of employment or service at the time of granting the
option, subject to regulatory approvals.

The number of Trust Units subject to options which may be
granted from time to time under the Option Plan shall not exceed 5,000,000 Trust
Units (which number may be decreased at any time and may be increased from time
to time, subject to regulatory approval and the approval of the Trust
Unitholders). The number of Trust Units reserved for issuance pursuant to
options granted to insiders of the Trust or Provident (or their advisors) shall
not exceed 10% of the total number of Trust Units then outstanding. Furthermore,
the issuance to insiders of the Trust or Provident (or their advisors) shall not
exceed or result

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in the issuance to such insider during a one year period of
more than 10% of the total number of Trust Units outstanding, nor may the
issuance of Trust Units held by such insider of the Trust or Provident (or their
advisors), and associates of such insider, within a one-year period, exceed 5%
of the total number of Trust Units then outstanding. In addition, the number of
Trust Units reserved for issuance to any one person pursuant to options shall
not exceed 5% of the total number of Trust Units then outstanding. Options are
not assignable or transferable. No financial assistance will be provided to
holders of options who wish to exercise their options to acquire Trust Units. As
of April 20, 2004, there were 4,094,465 options granted and outstanding under
the Option Plan.

The Trust is seeking to increase the number of Trust Units
available for issuance under the Option Plan from 5,000,000 to 8,000,000. The
proposed increase requires the approval of Unitholders and will be voted upon at
the Trust's annual and special meeting of Unitholders to be held on May 10,
2004.

> 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% 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% of the monthly cash
distribution, or (c) purchase new Trust Units under the optional unit purchase
plan at a subscription price of 100% 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.

> 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 the Trust
will not be maintained primarily for the benefit of Non-Residents and it shall
be the sole responsibility of Provident to monitor the holdings by Non-Residents
and 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.

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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 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 NonResident; (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% 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% of the trust's property has at any time consisted of "taxable
Canadian property". Prior to the Budget, Canadian resource property, including a
resource royalty, was not "taxable Canadian property" for this purpose, and
therefore a number of resource royalty trusts, including the Trust, were not
required to restrict non-resident ownership of their units. Under the Budget
proposals, the definition of "taxable Canadian property" for this purpose will
be amended so as to include Canadian resource property, and therefore resource
royalty trusts, including the Trust, will be required to restrict non-resident
ownership of their units prior to January 1, 2007.

> March 2004 Federal Budget

The Budget proposed to introduce changes to the Tax Act in three relevant
respects:

1. 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

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> without uncertainty, this is generally accepted to exist in
>   most situations where Non-Resident holders own significantly in excess of 50%
>   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% of the trust's property has at any time consisted of "taxable
>   Canadian property". Prior to the Budget, Canadian resource property, including
>   a resource royalty, was not "taxable Canadian property" for this purpose, and
>   therefore a number of resource royalty trusts, including the Trust, were not
>   required to restrict non-resident ownership of their units. Under the Budget
>   proposals, the definition of "taxable Canadian property" for this purpose will
>   be amended so as to include Canadian resource property, and therefore resource
>   royalty trusts, including the Trust, will be required to restrict non-resident
>   ownership of their units prior to January 1, 2007.

1. Pension funds will be restricted in their ownership of
  "business income trusts" after 2004 to 1% of the book value of the fund's
  assets and to no more than 5% of the units of any business income trust. This
  restriction generally will not apply to a pension fund's investment in
  resource royalty trusts or real estate investment trusts. However, as a result
  of the composition of assets held indirectly by the Trust it is uncertain
  whether or not the Trust will be a "business income trust" for these purposes.
2. After 2004, distributions to non-residents, other than
  distributions out of the income of the Trust (which are already subject to
  Canadian withholding tax) will become subject to a special 15% Canadian
  withholding tax. This withholding tax will generally not be refundable, except
  in certain circumstances where the non-resident Unitholder realizes a capital
  loss on the disposition of Trust Units. This measure may adversely impact
  non-resident Unitholders who are not able to deduct or credit such withholding
  tax against income taxes otherwise payable by them in the foreign
  jurisdiction.

> 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% of
the simple average of the closing price of the Trust Units on the principal
market on which the Trust Units are quoted for trading during the 10 trading day
period commencing immediately after the date on which the Trust Units are
surrendered for redemption; and (ii) the closing market price on the principal
market on which the Trust Units are quoted for trading on the date that the
Trust Units are surrendered for redemption.

The aggregate Market Redemption Price payable by the Trust in
respect of any Trust Units surrendered for redemption during any calendar month
shall be satisfied by way of a cash payment on the last day of the following
month. In certain circumstances, the aggregate Market Redemption Price payable
by the Trust may be satisfied by distributing notes having an aggregate
principal amount equal to the aggregate Market Redemption Price of the Trust
Units tendered for redemption.

It is anticipated that this redemption right will not be the
primary mechanism for holders of Trust Units to dispose of their Trust Units.
Notes which may be distributed in specie to holders of Trust Units in connection
with a redemption will not be listed on any stock exchange and no market is
expected 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.

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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:

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Trust Unitholder Rights Plan

Pursuant to a Unitholder Rights Plan Agreement entered into between the Trust
and Computershare Trust Company of Canada on March 6, 2001, the Trust has put in
place a unitholder rights plan.

The Unitholder Rights Plan is intended to address
deficiencies, which the Trust believes exist in current Canadian takeover bid
legislation. The purpose of the Unitholder Rights Plan is to afford both the
holders of Trust Units and Provident sufficient time to evaluate and respond to
an unsolicited offer made for the Trust Units. Further, the Unitholder Rights
Plan is intended to assist in ensuring that all holders of Trust Units have an
equal opportunity to participate in any takeover bid.

The following is a summary of the principal terms of the Unitholder Rights
Plan, which is qualified in its entirety by the actual text of the Unitholder
Rights Plan Agreement.

> Expiry of Unitholder Rights Plan

The Unitholder Rights Plan will expire at the end of the Trust's annual and
special meeting of Unitholders to be held on May 10, 2004.

> Issue of Rights

On the effective date of the Unitholder Rights Plan, one
right (a "Right") shall be issued and attached to each of the outstanding Trust
Units and will attach to each Trust Unit that is subsequently issued. Initially,
certificates representing Trust Units also represent the Rights.

> Rights Exercise Privilege

The Rights will separate from the Trust Units and will be
exercisable, subject to action by Provident, 10 trading days (the "Separation
Time") after a person has acquired, or commences a takeover bid to acquire, 20%
or more of the Trust Units, other than by an acquisition pursuant to a takeover
bid permitted by the Unitholder Rights Plan (a "Permitted Bid"). The acquisition
by any person (an "Acquiring Person") of 20% or more of the Trust Units, other
than by way of a Permitted Bid, is referred to as a "Flip-in Event". Any Rights
held by an Acquiring Person will become void upon the occurrence of a Flip-in
Event. In the absence of action by Provident and 10 days after the occurrence of
a Flip-in Event, each Right (other than those held by the Acquiring Person),
will permit the purchase of that number of Trust Units having an aggregate
market price (as defined in the Unitholder Rights Plan) equal to twice the
exercise price for an amount in cash equal to the exercise price (which the
Unitholder Rights Plan currently sets at $30).

The issue of the Rights is not initially dilutive. However, holders of Rights
not exercising their Rights upon the occurrence of a Flip-in Event may suffer
substantial dilution.

> Certificates and Transferability

After the Separation Time, the Rights will be evidenced by Rights
certificates, which will be transferable and traded separately from the Trust
Units.

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Permitted Bid Requirements

The requirements for a Permitted Bid include the following:

> (a)
>   the take-over bid must be
>   made to all holders of Trust Units, other than the Acquiring Person;
>   (b)the take-over bid
>   must contain, and the take-up and payment for securities tendered or deposited
>   is subject to, an irrevocable and unqualified provision that no Trust Units
>   will be taken up or paid for pursuant to any take-over bid prior to the close
>   of business on the date which is not less than 45 days following the date of
>   the take-over bid and only if at such date more than 50% of the Trust Units
>   held by independent holders of Trust Units shall have been deposited or
>   tendered pursuant to the take-over bid and not withdrawn;
>   (c)the take-over bid
>   contains an irrevocable and unqualified provision that unless the takeover bid
>   is withdrawn, Trust Units may be deposited pursuant to such take-over bid at
>   any time during the period of time between the date of the take-over bid and
>   the date on which Trust Units may be taken up and paid for and that any Trust
>   Units deposited pursuant to the take-over bid may be withdrawn until taken up
>   and paid for; and
>   (d)the take-over bid
>   must contain an irrevocable and unqualified provision that if, on the date on
>   which Trust Units may be taken up and paid for, more than 50% of the Trust
>   Units held by independent holders of Trust Units shall have been deposited
>   pursuant to the take-over bid and not withdrawn, the Acquiring Person will
>   make a public announcement of that fact and the take-over bid will remain open
>   for deposits and tenders of Trust Units for not less than 10 Business Days
>   from the date of such public announcement.

The Unitholder Rights Plan allows for a competing Permitted
Bid (a "Competing Permitted Bid") to be made while a Permitted Bid is in
existence. A Competing Permitted Bid must satisfy all the requirements of a
Permitted Bid (subject to certain exceptions).

> Waiver and Redemption

Provident may, prior to a Flip-in Event, waive the dilutive
effects of the Unitholder Rights Plan in respect of a particular Flip-in Event
resulting from a takeover bid made by way of a takeover bid circular to all
holders of the Trust Units, in which event such waiver would be deemed also to
be a waiver in respect of any other Flip-in Event occurring under a takeover bid
made by way of a takeover bid circular to all holders of the Trust Units prior
to the expiry of the takeover bid in respect of which the waiver is granted.
Provident may also waive the Unitholder Rights Plan in respect of a particular
Flip-in Event that has occurred through inadvertence, provided that the
Acquiring Person that inadvertently triggered such Flip-in Event reduces its
beneficial holdings to less than 20% of the outstanding Trust Units within 10
days or such other period as may be specified by Provident.

At any time prior to the occurrence of a Flip-in Event, Provident may at its
option redeem all, but not less than all, of the outstanding Rights at a price
of $0.00001 per Right.

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 Midstream NGL
Assets. Provident is also engaged in the acquisition,

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exploitation, development and production of crude oil and
natural gas in the Western Canadian Sedimentary Basin. Provident currently has
138 employees and consultants at its head office location and 181 employees and
contract operators located in several field offices within the core areas of
Lloydminster, west central Alberta, southern Alberta, southwest Saskatchewan,
southeast Saskatchewan and the NGL Midstream facility in Redwater, Alberta.

> 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 AMEX 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, including without limitation
all matters concerning the adoption of any Unitholder Rights Plan; (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 an amount equal
to 5% of the market capitalization ofthe Trust; (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.

> 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.

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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.

> Exchangeable Shares

Provident has also issued a total of 1,682,242 exchangeable
shares. All of the exchangeable shares are held by corporations related to two
senior officers of Provident and were issued in connection with the Trust's
management internalization transaction completed at the beginning of 2003.

The exchangeable shares are generally intended to represent
an economic equivalent to the Trust Units that the vendors would have received
from the sale of the common shares of the Manager had they elected to receive
Trust Units. Each exchangeable share is exchangeable for Trust Units on the
basis of an exchange ratio, initially equal to one, subject to certain
adjustments to reflect the cash distributions on the Trust Units.

The Trust has issued a Special Voting Unit to Computershare
Trust Company of Canada, the Trustee, for the benefit of the holders of the
exchangeable shares. The Special Voting Unit carries a number of votes,
exercisable at any meeting at which Unitholders are entitled to vote equal to
the number of Trust Units (rounded down to the nearest whole number) into which
the exchangeable shares are then exchangeable.

The exchangeable shares have substantially similar attributes to the
exchangeable shares issued by PAI in connection with the acquisition of Meota.
See "Provident Acquisitions Inc. - Exchangeable Shares".

Provident is authorized to issue an unlimited number of exchangeable shares,
issuable in series. As of April 20, 2004, there were 1,279,227 exchangeable
shares of Provident issued and outstanding.

> 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 $0.25 per barrel of oil equivalent (converting gas to oil at 6:1) (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 Midstream
NGL Assets flows from Provident to the Trust by way of interest payments and
principal repayments on notes issued by the Trust.

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Provident Holdings Trust and Provident Acquisitions L.P.

Provident LP holds certain southeast Alberta properties
acquired on May 1, 2002. See "Significant Acquisitions and Significant
Dispositions" in this Annual Information Form. Holdings Trust holds a 99%
interest in Provident LP and is managed by Provident. Holdings Trust is
wholly-owned by the Trust. The general partner of Provident LP is Provident.
Provident LP 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 LP after certain cost expenditures and deductions.

Provident Acquisitions Inc.

PAI holds certain Alberta and Saskatchewan properties that
were acquired through the purchase of Meota. PAI is managed by Provident and has
67% interest in 10101150 Saskatchewan Ltd. and a 0.00001% interest in 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.

> Exchangeable Shares

On October 1, 2002, PAI issued 5,585,136 million exchangeable
shares as partial consideration for the acquisition of Meota. The exchange ratio
for the exchangeable shares for the period October 1 to November 14, 2002 was
initially equal to one Trust Unit for one exchangeable share and is increased on
each date a distribution is paid by the Trust between October 1, 2002 and the
date the exchangeable share is exchanged, at the option of the holder, into
Trust Units. On January 15, 2005, all remaining exchangeable shares will be
automatically exchanged for Trust Units, subject to extension at the option of
the Trust.

The following is a summary description of the material provisions of the PAI
exchangeable shares:

> Ranking

The exchangeable shares rank prior to any common shares of
PAI and any other shares ranking junior to the exchangeable shares with respect
to the payment of dividends and the distribution of assets in the event of the
liquidation, dissolution or winding-up of PAI.

> Dividends

Holders of exchangeable shares are entitled to receive
dividends if, as and when declared by the board of directors of PAI. PAI does
not anticipate that any dividends will be declared in respect of the
exchangeable shares; however the board of directors of PAI has the right in its
sole discretion to do so.

> Retraction of exchangeable shares by Holders

Subject to the Retraction Call Right described below, a
holder of exchangeable shares is entitled at any time to require PAI to redeem
any or all of the exchangeable shares held by such holder for a retraction price
per exchangeable share equal to the value of that number of Trust Units equal to
the exchange ratio as at the retraction date (the "Retraction Price"), to be
satisfied by the delivery of that number of Trust Units. Fractional Trust Units
will not be delivered. Any amount payable on account of the Retraction Price
that includes a fractional Trust Unit will be rounded down to the nearest whole
number of Trust Units.

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Holders of the exchangeable shares may request redemption by
presenting to PAI or the exchangeable shares transfer agent a certificate or
certificates representing the number of exchangeable shares the holder desires
to have redeemed, together with a duly executed retraction request and such
other documents as may be reasonably required to effect the redemption of the
exchangeable shares. The redemption will become effective five business days
after the date on which PAI or the exchangeable shares transfer agent receives
the retraction request from the holder.

When a holder requests PAI to redeem the exchangeable shares,
the Trust, Provident or any subsidiary of either the Trust or Provident will
have an overriding right (the "Retraction Call Right") to purchase on the
retraction date all but not less than all of the exchangeable shares that the
holder has requested PAI to redeem at a purchase price per exchangeable share
equal to the Retraction Price, to be satisfied by the delivery of that number of
Trust Units having a value equal to the Retraction Price.

At the time of a retraction request by a holder of
exchangeable shares, PAI will immediately notify the Trust, Provident or a
subsidiary of either the Trust or Provident. The Trust, Provident or a
subsidiary of either the Trust or Provident must then advise PAI within two
business days as to whether the Retraction Call Right will be exercised. A
holder may revoke his or her retraction request at any time prior to the close
of business on the last business day immediately preceding the retraction date,
in which case the holder's exchangeable shares will neither be purchased by the
Trust, Provident or a subsidiary of either the Trust or Provident, nor be
redeemed by PAI. If the holder does not revoke his or her retraction request,
the exchangeable shares that the holder has requested PAI to redeem will on the
retraction date be purchased by the Trust, Provident or a subsidiary of either
the Trust or Provident or redeemed by PAI, as the case may be, in each case at a
purchase price per exchangeable share equal to the Retraction Price.

The Retraction Call Right may be exercised, at the election of Provident, by
either the Trust, Provident or a subsidiary of either the Trust or Provident.

> Redemption of exchangeable shares

Subject to applicable law and the Redemption Call Right, PAI:

> (a)will, on January
>   15, 2005 (the "Automatic Redemption Date"), redeem all but not less than all
>   of the then outstanding exchangeable shares for a redemption price per
>   exchangeable share equal to the value of that number of Trust Units equal to
>   the exchange ratio as at the last business day prior to that Redemption Date
>   (as that term is defined below) (the "Redemption Price"), to be satisfied by
>   the delivery of that number of Trust Units;
>   (b)may, at any time
>   when the aggregate number of issued and outstanding exchangeable shares is
>   less than 10% of the number of exchangeable shares issued (as such number of
>   shares may be adjusted as deemed appropriate by the board of directors of PAI
>   to give effect to any subdivision or consolidation of or stock dividend on the
>   exchangeable shares, any issuance or distribution of rights to acquire
>   exchangeable shares or securities exchangeable for or convertible into or
>   carrying rights to acquire exchangeable shares, any issue or distribution of
>   other securities or rights or evidences of indebtedness or assets, or any
>   other capital reorganization or other transaction involving or affecting the
>   exchangeable shares) (the "De Minimus Redemption Date" and, collectively with
>   an Automatic Redemption Date, a "Redemption Date"), redeem all but not less
>   than all of the then outstanding exchangeable shares for the Redemption Price
>   per exchangeable share; and

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> (c)will be deemed to
>   have redeemed all but not less than all of the then outstanding exchangeable
>   shares for the Redemption Price per exchangeable share immediately prior to
>   the time when the trust unit purchase rights issued pursuant to the unitholder
>   rights plan of the Trust (or pursuant to any successor or replacement rights
>   plan) would separate from the Trust Units and become exercisable.

Fractional Trust Units will not be delivered. Any amount payable on account
of the Redemption Price that includes a fractional Trust Unit will be rounded
down to the nearest whole number of Trust Units.

PAI will, at least 90 days prior to any Redemption Date,
provide the registered holders of the exchangeable shares with written notice of
the prospective redemption of the exchangeable shares by PAI, including the
number of exchangeable shares PAI intends to redeem. On or after the date that
such notice is provided, upon the holder's presentation and surrender of the
certificates representing the exchangeable shares and such other documents as
may be required at the registered office of PAI or the office of the
exchangeable shares transfer agent, PAI will deliver the Redemption Price to the
holder at the address of the holder recorded in PAI's security register or by
holding the Redemption Price for pickup by the holder at the registered office
of PAI or the office of the exchangeable shares transfer agent as specified in
the written notice. The accidental failure or omission to give any notice of
redemption to less than 10% of the holders of exchangeable shares (other than
the Trust) will not affect the validity of any redemption of exchangeable shares
pursuant to such notice.

The Trust, Provident or a subsidiary of either the Trust or
Provident have been granted a right (the "Redemption Call Right"),
notwithstanding a proposed redemption of the exchangeable shares by PAI on the
applicable Redemption Date, pursuant to the exchangeable share provisions, to
purchase on any Redemption Date all but not less than all of the exchangeable
shares then outstanding (other than exchangeable shares held by the Trust,
Provident or a subsidiary of either the Trust or Provident) in exchange for the
Redemption Price and, upon the exercise of the Redemption Call Right, the
holders of all of the then outstanding exchangeable shares will be obliged to
sell all such shares to the Trust, Provident or a subsidiary of either the Trust
or Provident, as applicable. If either the Trust, Provident or a subsidiary of
either the Trust or Provident exercises the Redemption Call Right, PAI's right
to redeem the exchangeable shares on the applicable Redemption Date will
terminate.

The Redemption Call Right may be exercised, at the election of Provident, by
either the Trust, Provident or a subsidiary of either the Trust or Provident.

> Non-resident Holders

Exchangeable shares have not been and will not be issued to a
resident of any foreign country. The obligation of the Trust, Provident or a
subsidiary of either the Trust or Provident to pay the Retraction Price or
Redemption Price in respect of the exchangeable shares which are held by a
resident of any foreign country shall be satisfied by delivering the Trust Units
which would have been received by the affected holder to the exchangeable shares
transfer agent who shall sell such Trust Units on the stock exchange on which
the Trust Units are then listed and, upon such sale, the rights of the affected
holder shall be limited to receiving the net proceeds of sale (net of applicable
taxes) upon surrender of the certificates representing such exchangeable shares.

> Voting Rights

The holders of exchangeable shares shall not be entitled to
vote exchangeable shares in respect of any matters concerning PAI. In accordance
with the voting and exchange trust agreement in respect of the exchangeable
shares, the Trust has issued a Special Voting Unit to Computershare Trust
Company of

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Canada, the Trustee, for the benefit of the holders (other
than the Trust, Provident or a subsidiary of either the Trust or Provident) of
the exchangeable shares. The Special Voting Unit carries a number of votes,
exercisable at any meeting at which Trust Unitholders are entitled to vote equal
to the number of Trust Units (rounded down to the nearest whole number) into
which the exchangeable shares are then exchangeable. With respect to any written
consent sought from the Trust Unitholders, each vote attached to the Special
Voting Unit will be exercisable in the same manner as set forth above.

Each holder of an exchangeable share on the record date for
any meeting at which Unitholders are entitled to vote will be entitled to
instruct the Trustee to exercise that number of votes attached to the Special
Voting Unit equal to the number of Trust Units (rounded down to the nearest
whole number) into which such exchangeable share is then exchangeable. The
Trustee will exercise each vote attached to the special voting unit only as
directed by the relevant holder and, in the absence of instructions from a
holder as to voting, will not exercise such votes.

The Trustee will send to the holders of the exchangeable
shares the notice of each meeting at which the Unitholders are entitled to vote,
together with the related meeting materials and a statement as to the manner in
which the holder may instruct the Trustee to exercise the votes attaching to the
Special Voting Unit, at the same time as the Trust sends such notice and
materials to the Unitholders. The Trustee will also send to the holders copies
of all information statements, interim and annual financial statements, reports
and other materials sent by the Trust to the Trust Unitholders at the same time
as such materials are sent to the Unitholders. To the extent such materials are
provided to the Trustee by the Trust, the Trustee will also send to the holders
all materials sent by third parties to Unitholders, including dissident proxy
circulars and tender and exchange offer circulars, as soon as possible after
such materials are first sent to Unitholders, and the Trust will use its
reasonable best efforts to obtain and deliver such materials to the Trustee.

All rights of a holder of exchangeable shares to exercise votes attached to
the Special Voting Unit will cease upon the exchange of all such holder's
exchangeable shares for Trust Units.

With the exception of administrative changes for the purpose
of adding covenants for the protection of the holders of the exchangeable
shares, making necessary amendments or curing ambiguities or clerical errors (in
each case provided that the board of directors of Provident and the Trustee are
of the opinion that such amendments are not prejudicial to the interests of the
holders of the exchangeable shares), the voting and exchange trust agreement may
not be amended without the approval of the holders of the exchangeable shares.

> Amendment and Approval

The rights, privileges, restrictions and conditions attaching
to the exchangeable shares may be changed only with the approval of the holders
thereof. Any such approval or any other approval or consent to be given by the
holders of the exchangeable shares will be sufficiently given if given in
accordance with applicable law and subject to a minimum requirement that such
approval or consent be evidenced by a resolution passed by not less than
two-thirds of the votes cast thereon (other than shares beneficially owned by
the Trust, Provident, or any of their subsidiaries and other affiliates) at a
meeting of the holders of the exchangeable shares duly called and held at which
holders of at least 20% of the then outstanding exchangeable shares are present
in person or represented by proxy. In the event that no such quorum is present
at such meeting within one-half hour after the time appointed therefor, then the
meeting will be adjourned to such place and time (not less than 10 days later)
as may be determined at the original meeting and the holders of exchangeable
shares present in person or represented by proxy at the adjourned meeting will
constitute a quorum thereat and may transact the business for which the meeting
was originally called. At the adjourned meeting, a resolution passed by the
affirmative vote of not less

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than two-thirds of the votes cast thereon will constitute the approval or
consent of the holders of the exchangeable shares.

The Manager

Prior to 2003, the principal business of the Manager was to
provide administrative and management services to the Trust including the
acquisition, exploitation, development and production of crude oil and natural
gas from the properties. Pursuant to the provisions of the Management Agreement,
the Manager provided certain management, administrative and support services to
the Trust and its affiliates, including those necessary: (a) to ensure
compliance by the Trust with continuous disclosure obligations under applicable
securities legislation; (b) to provide investor relations services; (c) to
provide or cause to be provided to holders of Trust Units all information to
which holders of Trust Units are entitled under the Trust Indenture; (d) to
call, hold and distribute materials including notices of meetings and
information circulars in respect of all necessary meetings of holders of Trust
Units; (e) to determine the amounts payable from time to time to holders of
Trust Units including Distributable Cash; and (f) to determine the timing and
terms of future offerings of Trust Units, if any.

The Manager was owned by Thomas W. Buchanan and Randall J.
Findlay and was incorporated solely for the purpose of providing management,
advisory and administration services to Provident and the Trust.

On November 22, 2002 the Trust, Provident, the Manager,
Scimitar Energy Limited and Hastings Street Management Limited (the "Vendors")
entered into a share purchase agreement pursuant to which Provident agreed to
purchase all of the issued and outstanding common shares of the Manager in
consideration of $18 million, payable by the issuance of an aggregate of
1,682,242 exchangeable shares at an agreed upon price of $10.70 per share,
subject to certain adjustments. Each exchangeable share issued to the Vendors is
exchangeable for Trust Units on the basis of an exchange ratio which takes into
account the cash distributions on the Trust Units. On the date of issuance of
the exchangeable shares, the exchange ratio was equal to one Trust Unit for each
exchangeable share.

As a condition of completing the internalization transaction,
the Vendors enter into escrow agreements. The escrow provisions resulted in all
exchangeable shares issued pursuant to the share purchase agreement being held
in escrow. The number of exchangeable shares held in escrow representing 25% of
the initial underlying Trust Units to be issued to the Vendors are releasable
per year beginning on June 30, 2003 and are also releasable in certain other
limited circumstances.

The escrow agreements also provide for the monthly release
from escrow of a number of exchangeable shares to account for the adjustment to
the exchange ratio as a result of distributions paid on the Trust Units. The
release of such exchangeable shares effectively releases to the Vendors the
distributions paid on the Trust Units. The number of exchangeable shares to be
released from escrow to account for such distributions on the Trust Units shall
be determined by multiplying the number of exchangeable shares held by a Vendor
on the last day of the month in question which have not been released from
escrow or are not releasable from escrow by the difference between the exchange
ratio in effect on the last day of the month in question and the exchange ratio
in effect on the last day of the month immediately preceding the month in
question and dividing the product thereof by the exchange ratio in effect on the
last day of the month in question.

In the event of a change of control of the Trust or
Provident, all exchangeable shares held in escrow will be released to the
underlying holders. In addition, the escrow agreements provide for early release
of the securities in the event of the death or disability of either Thomas
Buchanan or Randall Findlay, or if either is terminated from their employment
with Provident or any other subsidiary of the Trust without just

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cause. Securities held in escrow may be charged, pledged or encumbered,
provided that the securities will remain in escrow pursuant to the terms of the
escrow agreements.

In addition, the exchangeable shares held in escrow which
have not been released or are not releasable from escrow at the applicable time
will be subject to cancellation and forfeiture by Provident if the relevant
individual voluntarily resigns from Provident or any other subsidiary of the
Trust.

The escrow provisions and forfeiture provisions are intended to enhance
alignment between management and Unitholder interests and to retain management.

In connection with the closing of the internalization
transaction, Provident entered into executive employment agreements with each of
Mr. Buchanan and Mr. Findlay. Under the terms of the executive employment
agreements, each of Mr. Buchanan and Mr. Findlay receives an annual salary of
$250,000 for the first year of services and thereafter as determined by the
Board of Directors annually, provided that each annual determination shall not
be less than the previous year's annual salary. Mr. Buchanan and Mr. Findlay
will also be entitled to a cash bonus of up to 50% of his annual salary in an
amount determined by the Board of Directors based on certain established
criteria.

In addition, options to purchase 500,000 Trust Units were
granted to each of Mr. Buchanan and Mr. Findlay effective January 1, 2003. Such
options vest as to 1/3 immediately and 1/3 on each subsequent anniversary of the
grant.

Each of Mr. Buchanan and Mr. Findlay will also receive and
participate in any and all fringe benefit plans, coverages and other perquisites
made available from time to time to Provident's senior officers and executives.

In the event of a change of control or termination of
employment for any reason other than cause, each of Mr. Buchanan and Mr. Findlay
will receive two times the aggregate of his then current salary and the bonus
paid to him in respect of the most recently completed financial year.

It has been agreed that each of Mr. Buchanan and Mr. Findlay
will be nominated by the Board of Directors for a position as a director of
Provident at each meeting of Unitholders at which directors of Provident are
elected.

GENERAL DEVELOPMENT OF THE BUSINESS OF THE TRUST AND PROVIDENT

The business and history of Provident, and its predecessor
Founders, are detailed in the following discussion. This information provides
relevant background to the growth of Founders and the decision to convert
Founders into a cash distributing energy trust.

In 1997, Founders achieved significant production growth
through an aggressive horizontal drilling program that focussed on exploiting
certain southeast Saskatchewan oil properties that were acquired in March 1996.
The use of three-dimensional seismic and horizontal drilling techniques resulted
in nine successful horizontal oil wells in the Founders operated areas of
Hartaven and Weir Hill. Exploration drilling during 1997 resulted in two
successful deep exploratory Ordovician oil wells in the Hartaven area of
southeast Saskatchewan. During 1997, Founders also increased its undeveloped
land position by 48,325 net acres to total 60,816 net acres. Production volumes
for 1997 averaged 1,762 barrels of oil equivalent per day.

In 1998, Founders realized significant gains in crude oil and natural gas
production and reserves as a result of a significant multi-zone natural gas
discovery at Pouce Coupe in northwest Alberta and the

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December 22, 1998 acquisition of Opal. Production volumes
averaged 2,489 barrels of oil equivalent per day and undeveloped land holdings
increased by 99,452 net acres to total 160,268 net acres. The acquisition of
Opal ranked as Founders' largest transaction at the time and provided Founders
with a new Saskatchewan heavy oil core area in close proximity to Lloydminster
as well as a natural gas prone core area in West Central Alberta. On a proven
reserve basis the Opal acquisition provided 8.2 million barrels of oil
equivalent of which 46 percent were natural gas and on a proven plus half
probable basis, Founders acquired 10.2 million barrels of oil equivalent of
which 48 percent were natural gas reserves. Opal was a value-driven acquisition
that significantly enhanced Founders' competitive position in the gas-prone area
of West Central Alberta and provided Founders with a new core growth area for
heavy oil in close proximity to Lloydminster.

In 1999, high debt levels, historically low crude oil prices
and limited equity markets significantly impaired Founders' growth objectives
for the year. Early in 1999, management recognized the need to deal with
Founders' debt levels to improve Founders' financial flexibility. Accordingly,
to repay bank debt, a $15 million subordinated convertible debenture financing
was completed in June 1999 and Founders commenced a program of identifying and
selling $28.8 million of non-core assets throughout the year. These successful
initiatives, coupled with drilling success during the second half of 1999,
significantly improved the balance sheet and created a more flexible financial
structure to allow Founders to aggressively compete in its core growth areas. In
addition, during the third quarter of 1999, an extensive review was undertaken
by management and the board of directors to evaluate and recommend strategic
alternatives to maximize Founders' potential. As a result of this process,
Founders refocused and simplified its business strategy to create consistent
growth in shareholder value through efficient use of capital and technical
resources. Daily 1999 production volumes averaged 2,874 bpd of crude oil and
natural gas liquids and 12.3 mmcfd of natural gas for a total oil equivalent
production of 4,922 boed.

During 2000, Founders focused its activities in the two core
areas of West Central Alberta and Lloydminster. During the year, Founders
participated in the drilling of a total of 31 (27.3 net) wells, resulting in 22
(20.3 net) crude oil wells, six (4.9 net) gas wells and three (2.1 net) dry
holes for an overall success rate of 90 percent. During 2000, a total of 18
wells were drilled in the Lloydminster heavy oil area with a 100 percent success
rate. In the gas prone area of West Central Alberta, Founders drilled or
participated in drilling nine (7.0 net) wells for an overall success rate of 67
percent. During 2000, daily production volumes averaged 2,440 bpd of crude oil
and natural gas liquids and 10.6 mmcfd of natural gas for a total oil equivalent
production of 4,208 boed compared to an average daily production rate of 4,922
boed in 1999. The reduction in daily production volumes for 2000 compared to
1999 is attributed to the sale of approximately 1,200 boed of annualized
non-core production throughout 1999. Founders' exit production for the year was
slightly in excess of 4,300 boed.

During 2000, management believed that Founders, along with
the vast majority of other junior E & P companies, was significantly undervalued
by the market. As a result, Founders' board of directors reviewed several
options for the company with a view to increasing shareholder value. At this
time, it was the collective view of the board of directors that the Western
Canadian Sedimentary Basin had become largely a mature basin with an operating
emphasis on exploitation. In reviewing appropriate structures for a maturing
basin, management believed the trust structure was the most suited structure for
acquiring mid-life to mature assets and for harvesting and paying out the cash
flow in a low risk, cost effective manner. The board of directors believed that
a trust structure would maximize the financial return for the Founders'
shareholders through the creation of a yield-based investment that could take
maximum advantage of the strong commodity prices and market fundamentals
currently prevailing in the oil and gas sector.

On March 5, 2001, the shareholders of Founders approved the reorganization of
Founders into Provident Energy Trust. The transaction, accomplished by way of a
plan of arrangement resulted in the

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shareholders of Founders receiving one Trust Unit in exchange for each three
common shares of Founders.

On May 25, 2001, the Trust and Provident completed the
acquisition of the common shares of Maxx pursuant to the Maxx Arrangement in a
transaction valued at $126.4 million. The acquisition of Maxx increased the
total number of Trust Units outstanding to 14,586,821 Trust Units.

On August 29, 2001, the Trust completed a treasury and
secondary offering of 2,435,500 trust units for gross proceeds of $26.425
million. On December 13, 2001, in conjunction with the acquisition of Richland,
the Trust completed a treasury offering of 4,000,000 Trust Units for gross
proceeds of $35.0 million.

On January 15, 2002, the Trust and Provident completed the
Richland Arrangement. The acquisition of Richland for $102.6 million increased
the total number of Trust Units outstanding as at that date, to 32,179,546 Trust
Units.

On May 1, 2002, the Trust and Provident completed the
acquisition of the Acquired Properties located in southeast Alberta for a
purchase price of approximately $72.0 million, payable in cash. In conjunction
with the acquisition of the Acquired Properties, the Trust completed a
concurrent treasury offering of 3,900,000 Trust units and $64.41 million
principal amount of 10.5% Debentures for gross proceeds of $103.8 million.

On October 1, 2002, the Trust, Provident and PAI completed
the acquisition of all of the Meota common shares pursuant to a takeover bid
circular in a transaction valued at $254.4 million. The acquisition of Meota
increased the total number of Trust Units outstanding as at that date, to
51,851,921.

On September 30, 2003, Provident completed the acquisition of
the Redwater natural gas liquids processing business from Williams Canada for an
aggregate purchase price of approximately $298.6 million (including costs
associated with the acquisition), subject to certain adjustments. The Midstream
NGL Assets acquired pursuant to the Redwater Acquisition consisted of a natural
gas gathering system and processing plant, as well as an NGL extraction plant,
fractionation facilities, transportation systems and storage assets owned by
Williams Canada. The Midstream NGL Assets are strategically located in one of
the four main natural gas liquids hubs in North America and have an
approximately 25% share of NGL processing capacity in western Canada with a
significant amount of its capacity contracted on a long-term fee for service or
fixed margin contract basis.

In connection with the Redwater Acquisition, the Trust
completed a public offering of 19,205,000 Trust Units and $75,000,000 principal
amount of 8.75% Debentures for gross proceeds of $276,653,000. The net proceeds
from the offering were used to fund the Redwater Acquisition.

On October 21, 2003, the Trust announced the appointment of
Norman Gish to the Board of Directors of Provident and the appointments of
Andrew Gruszecki as Vice President of the NGL Services division of Provident and
Gary Kline as Vice President of Commercial Development and Risk Management.

On January 12, 2004, the Trust announced the appointment of Dr. Robert
Mitchell to the Board of Directors of Provident.

On February 4, 2004, the Trust completed a public offering of
4,500,000 Trust Units for gross proceeds of $50,400,000. The net proceeds will
be used to fund a portion of the Trust's 2004 capital expenditure program and to
repay debt.

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On April 6, 2004, the Trust, Provident, Olympia Energy Inc.
("Olympia") and 1101130 Alberta Ltd. ("1101130") entered into an arrangement
agreement providing for the acquisition by the Trust of all of the issued and
outstanding common shares of Olympia pursuant to a plan of arrangement. In
connection with the plan of arrangement, certain exploration and development
properties of Olympia will be transferred to 1101130, a newly created company,
the shares of which will be distributed to Olympia's shareholders under the plan
of arrangement. The acquisition is expected to be completed at the end of May
2004.

On April 6, 2004, the Trust, Provident, Viracocha Energy Inc.
("Viracocha") and 1100974 Alberta Inc. ("1100974") entered into an arrangement
agreement providing for the acquisition by the Trust of all of the issued and
outstanding common shares of Viracocha pursuant to a plan of arrangement. In
connection with the plan of arrangement, certain exploration and development
properties of Viracocha in Alberta will be transferred to 1100974, a newly
created company, the shares of which will be distributed to Viracocha's
shareholders under the plan of arrangement. The acquisition is expected to be
completed at the end of May 2004.

SIGNIFICANT ACQUISITIONS

Founders Arrangement

From the end of 1999 and throughout 2000, an extensive review
was undertaken by management and the Board of Directors to evaluate Founders'
asset base and future growth prospects in relation to the current industry
environment and to consider various strategic alternatives. As part of this
review, it was determined that the Western Canadian Sedimentary Basin had become
largely a mature basin with limited new growth potential. Finding costs have
consistently trended upwards over the past few years indicating that large new
quantities of oil and gas are becoming more difficult to find. Despite extremely
strong commodity prices and fundamentals, the majority of junior Canadian
exploration and production ("E&P") companies, including Founders, continued to
trade at very low valuations making it difficult to acquire properties or
companies or access growth capital without being extremely dilutive to
shareholders. At the same time, the Canadian oil and gas trust sector was
trading at much stronger valuations than the E&P sector and raised more than
$700 million of new equity during 2000. In addition, many Canadian oil and gas
trusts used their trust units as currency in completing more than $2 billion of
corporate and property acquisitions in 2000 by the sector. After an extensive
review of Founders' asset base and detailed production and cash flow modeling,
the Board of Directors concluded that the best alternative for maximizing
shareholder value would be to convert Founders into an oil and gas trust.

The purpose of the Founders Arrangement was to convert
Founders from a corporate entity concentrating on growth through the
reinvestment of cash flow to a trust entity which will distribute a substantial
portion of cash flow to Unitholders. The Founders Arrangement resulted in each
shareholder ultimately receiving one Trust Unit for every three Founders common
shares held with a cash payment in respect of any fractional interests. The
Founders Arrangement also resulted in the termination of the shareholder rights
plan of Founders and the adoption of the Unitholder Rights Plan containing
substantially the same provisions as the Founders shareholder rights plan.

Maxx Arrangement

On March 26, 2001, Provident, Maxx and the Trust entered into
an arrangement agreement with Maxx which provided for implementation of the Maxx
Arrangement pursuant to Section 186 of the ABCA. The Maxx Arrangement became
effective on May 25, 2001.

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Each issued and outstanding Maxx common share was exchanged
for $7.00 cash for each Maxx common share for those Maxx shareholders that
elected to receive all cash or $1.9745 cash and 0.4523 of a Trust Unit for those
Maxx shareholders that elected to receive all Trust Units.

The Maxx Arrangement resulted in a total of $35.4 million in
cash and 7,475,000 Trust Units being issued to acquire all of the issued and
outstanding shares of Maxx. Maxx and Provident were amalgamated and continued as
one corporation, under the name "Provident Energy Ltd."

Provident and Maxx each had three focused and matching core
operating areas in the Lloydminster area of Alberta and Saskatchewan, south-east
Saskatchewan and west central Alberta. The acquisition of Maxx resulted in
financial and operational synergies due to the similar nature of operations and
proximity of these properties. These synergies resulted in reduced general and
administration expenses, operational cost reduction opportunities and the
ability to access capital investment opportunities. As a result of the
acquisition of Maxx, Provident's daily average production increased from 4,800
barrels of oil equivalent per day to 12,500 boed, including 6,300 barrels of
conventional heavy crude oil, 1,700 barrels per day of light crude oil, 800
barrels of natural gas liquids and 20.6 mmcfd of natural gas. Provident's proven
reserves increased by 167 percent from 10.6 Mboe to 28.4 Mboe and established
reserves increased by 153 percent from 13.1 Mboe to 33.2 Mboe.

Richland Arrangement

On November 26, 2001, Provident, Richland, 961982 Alberta
Ltd. ("Terraquest") and the Trust entered into an arrangement agreement with
Richland which provided for implementation of the Richland Arrangement pursuant
to Section 186 of the ABCA. The Richland Arrangement became effective on January
16, 2002. Under the terms of the Richland Arrangement, Richland shareholders
received 0.4 of a Trust Unit and one share of Terraquest for each issued and
outstanding common share of Richland. Pursuant to the plan of arrangement, each
issued and outstanding common share of Richland was exchanged by Richland
shareholders for one newly created Class A Share and one Class B Share of
Richland. As part of the Richland Arrangement, upon completion of the sale of
certain assets of Richland (the "Terraquest Assets") to Terraquest for common
shares of Terraquest ("Terraquest Shares"), Richland redeemed all of the issued
and outstanding Class B Shares held by Richland shareholders in consideration
for the transfer of the Terraquest Shares held by Richland for the Class B
Shares held by Richland shareholders. Each issued and outstanding Class A Share
held by Richland shareholders was then exchanged for a note, which was
immediately redeemed for 0.4 of a Trust Unit.

The Terraquest Assets sold by Richland to Terraquest as part
of the Richland Arrangement were comprised of certain producing properties of
Richland located in southern and northwest Alberta which represented production
as at September 30, 2001 of approximately 200 boed, 426 mboe of proved reserves,
507 mboe of established reserves (defined as proved reserves plus 50% probable
reserves)and 88,000 net acres of undeveloped lands and associated
seismic data. Pursuant to the Richland Arrangement Agreement, Provident received
gross overriding royalties on industry standard terms on certain of the
Terraquest properties.

The Richland Arrangement became effective on January 16, 2002
following the approval of the Richland shareholders at a special meeting held on
January 15, 2002. Provident and Richland were then amalgamated, continuing as
"Provident Energy Ltd.". A total of 11,157,225 Trust Units were issued by the
Trust to acquire all of the issued and outstanding shares of Richland. As part
of the acquisition of Richland, Provident assumed Richland's debt, net of
working capital, of approximately $83 million.

Following the Richland Arrangement, Provident's daily average production
increased to approximately 17,000 barrels of oil equivalent per day comprising
of 40 percent natural gas, 33 percent cold

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conventional heavy oil and 27 percent light crude oil and
natural gas liquids. The assets of Richland have diversified Provident's
production mix, which, prior to the Richland Arrangement, was weighted 55
percent to heavy oil. The Richland assets are close to Provident's existing
operations in west central Alberta and southeast Saskatchewan and provided a new
core area in southern Alberta.

Southeast Alberta Property Acquisition

On March 26, 2002, Provident entered into an agreement of
purchase and sale with the Canadian subsidiaries of a U.S. based exploration and
production company providing for the acquisition by Provident of certain oil and
gas properties for a purchase price of $72.0 million (subject to adjustment),
payable in cash. The right to acquire the Acquired Properties was subsequently
assigned to Provident LP. The acquisition of the Acquired Properties was
effective April 1, 2002 and closed on May 1, 2002.

The Acquired Properties consist primarily of mature light oil
and natural gas assets located in southeast Alberta producing approximately
3,600 boed. The assets are comprised primarily of high working interest,
operated properties with year round operating access. The Acquired Properties
met the Trust's objectives of increasing cash available for distribution and net
asset value on a per unit basis.

Meota Takeover

On August 13, 2002 PAI agreed to acquire all of the issued
and outstanding shares of Meota by way of a takeover bid. PAI successfully
completed theacquisition of all of the issued and outstanding Meota
shares on October 2, 2002. The offer for each share consisted of: (i) Cdn$4.60
cash, or (ii) 0.415 Trust Units, or (iii) 0.415 exchangeable shares of Provident
Acquisitions, or (iv) a combination thereof (subject to certain limitations).

The completion of the acquisition of Meota resulted in the payment of $27.1
million cash, the issuance of 14,517,184 Trust Units, and the issuance of
5,858,136 exchangeable shares of PAI.

The transaction added approximately 11,400 boe per day of
natural gas weighted production from assets that generally overlapped
Provident's existing core areas, established a new core area in southwest
Saskatchewan, increased the Trust's proved developed producing, total proven and
established reserves base and helped continue to diversify production base and
mix. The transaction was 15 percent accretive to cash flow and neutral to net
asset value, on a per unit basis. The Meota assets were comprised predominately
of quality, operated, high-netback natural gas producing properties in
established areas of operation.

Redwater Acquisition

On September 30, 2003, Provident completed the acquisition of
the Redwater natural gas liquids processing business from Williams Canada for an
aggregate purchase price of approximately $298.6 million (including costs
associated with the acquisition), subject to certain adjustments. The Midstream
NGL Assets acquired pursuant to the Redwater Acquisition consisted of a natural
gas gathering system and processing plant, as well as an NGL extraction plant,
fractionation facilities, transportation systems and storage assets owned by
Williams Canada. The Midstream NGL Assets are strategically located in one of
the four main natural gas liquids hubs in North America and have an
approximately 25% share of NGL processing capacity in western Canada with a
significant amount of its capacity contracted on a long-term fee for service or
fixed margin contract basis.

In particular, the Midstream NGL Assets consist of a natural gas liquids
gathering system, an NGL extraction plant, fractionation facilities,
transportation systems and storage assets owned by Williams

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Canada and are comprised of (i) a 65 kilometre in length six
inch NGLs pipeline originating at the West Stoddart Plant and terminating at the
Younger to Boundary Lake Pipeline and associated interconnects to the Younger
Plant; (ii) all real and personal property comprising the Mile Post 73 Truck
Terminal including all fixtures and equipment appurtenant to such facility or
used or held for use in connection therewith; (iii) all of Williams Canada's
43.3% interest in the real and personal property comprising the extraction
straddle plant commonly referred to as the "Younger Plant"; (iv) three liquids
pipelines commonly known as the "Liquids Pipeline"; (v) an eight inch NGLs
pipeline, 85 kilometres in length known as the "Hamburg to Clearhills Pipeline"
originating at the Hamburg meter station and terminating at the Clearhills meter
station; (vi) a ten inch NGLs pipeline, 169 kilometres in length known as the "Clearhills
to LaGlace Pipeline" originating at the Clearhills meter station and terminating
at the LaGlace tube storage facility; (vii) the LaGlace tube storage facility
located near LaGlace, Alberta and consisting of forty-eight inch tube storage
for up to 30,000 barrels of NGLs; (viii) a 65,000 barrel per day capacity
fractionation plant, salt caverns storage, rail and truck loading and unloading
racks, located 50 kilometres northeast of Edmonton in Sturgeon County known as
the "Redwater Fractionation and Storage Facility"; (ix) seven associated product
lines to and from the Redwater Fractionation and Storage Facility
interconnecting to existing and future infrastructure within the Fort
Saskatchewan area; and (x) all agreements, contracts, documents, permits, land
rights, leases of vehicles and equipment and books and records related to the
above.

The Midstream NGL Assets to be acquired extend from natural gas rich
northeastern British Columbia down through central Alberta to the Redwater
facility north of Fort Saskatchewan.

Provident believes the Redwater Acquisition will provide a
long term lower risk diversified source of cash flow. A significant amount of
the Redwater system's capacity and cash flow is contracted through long-term fee
for service and fixed margin contracts with major oil and gas producers and
petrochemical businesses. More than two-thirds of the plant's volume is
contracted for 10 years or longer. As a result, Provident believes its economic
life will be increased on a cash flow basis due to the stable fee-based
contribution from long-life midstream assets.

Strategically located in one of four main NGL hubs in North
America, the Redwater facility has an approximately 25% share of NGL processing
capacity in western Canada and is one of the most modern and integrated NGL
systems in Canada. The following table sets forth certain operational
information for the Midstream NGL Assets.

|                             |  |               |  |           |                 |                     |  | Approximate      |           | 
|---------------------------- |  | ------------- |  | --------- | --------------- | ------------------- |  | ---------------- | --------- | 
|                             |  |               |  |           |                 |                     |  | Net NGL Capacity |           | 
|                             |  |               |  | Ownership |                 |                     |  |                  | Propane   | 
|Facility                     |  | Facility Type |  | Interest  |                 | Location            |  | Ethane           | Plus      | 
|                             |  |               |  |           |                 |                     |  | (mbbls/d)        | (mbbls/d) | 
|                             |  |               |  |           |                 |                     |  |                  |           | 
|Younger
    Plant            |  | Extraction    |  | 43.33%    |                 | Taylor,
    B.C.    |  | 11(1)            | 6(1)      | 
|                             |  |               |  |           |                 |                     |  |                  |           | 
|Liquids Gathering
    System |  | Gathering     |  | 100%      |                 | NE BC/
    NW AB    |  | -                | -         | 
|                             |  |               |  |           | to
    Redwater |                     |  |                  |           | 
|                             |  |               |  |           |                 |                     |  |                  |           | 
|Redwater Facility            |  | Fractionation |  | 100%      |                 | NE of
    Edmonton, |  | 25(2)            | 40(2)     | 
|                             |  |               |  |           |                 | AB                  |  |                  |           | 

Notes:

(1) Represents capacity from ownership interest in facility. 
(2) Represents fractionation capacity.

The Midstream NGL Assets have been integrated into Provident
and are run as a separate business unit. Financial reporting is done on a
segmented basis to provide transparency on the performance of both the midstream
and oil and gas production businesses. The midstream business is managed by
operations and

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commercial teams that joined Provident from Williams Canada, all of whom have
significant midstream experience and expertise.

The Midstream NGL Assets produced earnings before interest, taxes and
depreciation of $10,200,000 and cash flow of $9,000,000 in the fourth quarter of
2003.

Proposed Acquisition of Viracocha Energy Inc.

On April 6, 2004, the Trust, Provident, Viracocha and 1100974
entered into an arrangement agreement providing for the acquisition of all of
the issued and outstanding common shares of Viracocha, a publicly traded company
listed on the TSX pursuant to a plan of arrangement. The transaction is valued
at approximately $205.9 million, including the assumption by the Trust of $52
million of debt and working capital.

In accordance with the plan of arrangement, each share of
Viracocha will be exchanged for 0.248 of a Trust Unit, representing a value of
$2.71 per share of Viracocha, based upon the 30 day weighted average trading
price of $10.93 for the Trust Units on the TSX. Alternatively, in lieu of
receiving Trust Units, shareholders of Viracocha may elect to receive 0.248 of
an exchangeable share of Provident for each share of Viracocha, or may elect to
receive a combination of Trust Units and exchangeable shares of Provident. Under
the terms of the plan of arrangement, the aggregate number of exchangeable
shares of Provident issuable to Viracocha shareholders is limited to 1,325,000.
The exchangeable shares of Provident to be issued in connection with the
acquisition of Viracocha will be a different series of exchangeable shares than
the exchangeable shares issued to the Vendors in connection with the management
internalization transaction, but will have substantially similar attributes.

The obligations of the Trust, Provident and Viracocha to
complete the plan of arrangement are subject to, among other conditions, receipt
of all shareholder, court and regulatory approvals. It is anticipated that the
special meeting of Viracocha shareholders will be held at the end of May 2004,
with the closing of the acquisition to occur immediately following shareholder
approval.

Viracocha's producing properties significantly overlap with
Provident's existing operations in the Southern and East Central Alberta
regions. Upon completion of the plan of arrangement, Provident will have
acquired approximately 79,000 net acres of undeveloped land, excluding land
transferred to 1100974.

Proposed Acquisition of Olympia Energy Inc.

On April 6, 2004, the Trust, Provident, Olympia and 1101130
entered into an arrangement agreement providing for the acquisition of all of
the issued and outstanding common shares of Olympia, a publicly traded company
listed on the TSX pursuant to a plan of arrangement. The transaction is valued
at approximately $217.6 million, including the assumption by the Trust of $56.6
million of debt and working capital.

In accordance with the plan of arrangement, each share of
Olympia will be exchanged for 0.345 of a trust unit, representing a value of
$3.77 per share of Olympia, based upon the 30 day weighted average trading price
of $10.93 for the Trust Units on the TSX. Alternatively, in lieu of receiving
Trust Units, shareholders of Olympia may elect to receive 0.345 of an
exchangeable share of Provident for each share of Olympia, or may elect to
receive a combination of Trust Units and exchangeable shares of Provident. Under
the terms of the plan of arrangement, the aggregate number of exchangeable
shares of Provident issuable to Olympia shareholders is limited to 1,325,000.
The exchangeable shares of Provident to be issued in connection with the
acquisition of Olympia will be a different series of exchangeable shares than

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the exchangeable shares issued to the Vendors in connection with the
management internalization transaction, but will have substantially similar
attributes.

The obligations of the Trust, Provident and Olympia to
complete the plan of arrangement are subject to, among other conditions, receipt
of all shareholder, court and regulatory approvals. It is anticipated that the
special meeting of Olympia shareholders will be held at the end of May 2004,
with the closing of the acquisition to occur immediately following shareholder
approval.

Olympia's major production properties are located within
Provident's West Central Alberta core area, primarily in the Lochend, Wildcat
Hills and Bottrel areas. Olympia also has production in the Suffield
Atlee/Buffalo area as well as in Northern Alberta in Little Horse and Moon
Creek. Upon completion of the plan of arrangement, Provident will have acquired
approximately 95,000 net acres of undeveloped land, excluding land transferred
to 1101130.

CORPORATE STRATEGY AND 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 midstream services 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 operations are currently
located in five core regions in the Western Canadian Sedimentary basin. These
areas generally offer low to medium risk development potential, a well developed
operational infrastructure and year round access, all of which is ideally suited
to a trust. Provident will focus its development activities on low risk drilling
opportunities that can be used to partially offset production declines.

Provident's midstream services business adds a new dimension
to the Trust - one with minimal on-going capital requirements and reduced
exposure to commodity price risk. 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.

A consistent, disciplined integrated risk management strategy
will be employed by Provident, focusing on stabilizing monthly cash
distributions to Unitholders. To this end, Provident plans to use both financial
and physical contracts to reduce the volatility of crude, natural gas and
natural gas liquids prices.

Provident's main vehicle for growth will continue to be
acquisitions both in its oil and gas business and energy infrastructure
business. Acquisition opportunities will continue to be evaluated against the
criteria of being accretive to cash flow and net asset value.

Commodity Price Risk Management Program

> Financial Risk Management

Provident's integrated risk management program is a tool employed to protect
Provident's employees, stakeholders, assets, environment and reputation. It is
also used to achieve more predictable and stable

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cash distributions. Provident's definition of risk is broad and so too are
the policies and procedures Provident uses to identify, monitor, measure and
mitigate business and market risks.

Provident is exposed to all the normal business and market
risks inherent within the oil, natural gas and natural gas liquids business,
including commodity price risk, foreign-currency rate risk, interest rate risk,
and counterparty credit risk. Since its inception, Provident has used financial
hedging instruments to manage the commodity and foreign exchange exposures
associated with its revenue stream.

In 2003, Provident broadened the scope of its risk management
activities hiring additional internal expertise and implementing an Integrated
Risk Management Program that cuts across business lines and commodities, and
incorporates systematic programs to identify, monitor, measure and mitigate
business and market risks. Provident also established the officer level Risk
Management Committee ("RMC"), members of which include Provident's chief
executive officer, president, chief financial officer and vice president of
commercial development and risk management.

> Commodity Price Risk

Provident's Commodity Price Risk Management Program ("CPRMP")
involves a disciplined hedging strategy and use of derivative instruments to
minimize price risk associated with the volatility of commodity prices. These
instruments may include fixed for floating swaps, costless collars, puts, calls,
and fixed and indexed referenced pricing.

> Oil and Natural Gas Hedging

In its oil and natural gas production business, Provident
consistently layers in hedging positions such that it will have 50 to 70 percent
of production hedged 12 months forward and 25 to 50 percent hedged 12 to 24
months out. The decisions to enter into hedge positions and risk management
strategy selection are made by senior officers of Provident who are also members
of Provident's RMC. The RMC receives input and commodity expertise from each
business unit in the decisionmaking 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.

The result of Provident's hedging program in 2003 was an
opportunity cost of $49 million ($0.71 per unit). In 2003, 46 percent ($22.6
million) of Provident's opportunity cost was realized in the first quarter.
During this period, world commodity spot prices were pushed higher than the
prices at which Provident was hedged during the fourth quarter of 2002. The spot
price increase was primarily due to market perception of a supply shortage
created by a petroleum worker strike in Venezuela and reduced exports from the
Persian Gulf resulting from the U.S. invasion of Iraq.

Although Provident experienced opportunity costs in 2003,
Provident remains committed to its CPRMP. In 2003, Provident's hedging program
achieved its goal of stabilizing cash flows. At the same time it allowed
Provident to capture the higher commodity prices realized in the market during
2003 on the unhedged portion of its production. Over the long-term, Provident
believes a disciplined and consistent approach to commodity price risk
management will reduce the volatility of cash flow and provide for a more
predictable range of distributions.

> Natural Gas Liquids

In September 2003, Provident acquired the Midstream NGL
Assets and entered the midstream business. Provident's midstream services
business has a commodity price risk profile that differs from that of
Provident's oil and natural gas production business. In the oil and natural gas
production business

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Provident hedges to protect absolute prices. In the midstream services
business Provident hedges to protect the margins created through the buying,
processing, and selling of NGLs.

The commodity price exposure in Provident's midstream
operations is mitigated through long-term, fee-based and fixed margin contracts
that reduce the effects of fluctuating natural gas feedstock and NGL prices. NGL
sales transactions are usually executed based on a common reference price. When
the buy and sell occur in the same month, the fixed margin between the prices is
recovered. In the event of inter-month transactions, commodity prices are
actively managed through a hedging program for the midstream services unit in
accordance with Provident's CPRMP. NGLs are hedged utilizing their respective
commodities except for ethane, where volumes are hedged utilizing natural gas as
its primary sales and feedstock reference price.

> Foreign Currency

A substantial portion of prices received for sales of crude
oil, natural gas and certain NGL products are denominated in or referenced to
the U.S. dollar. In the Canadian oil, natural gas and NGL businesses however,
the majority of costs are denominated in Canadian dollars. As a result, changes
in the U.S./Canadian dollar exchange rate can have positive or negative effects
on oil and natural gas field netbacks and NGL margins.

Provident manages its exposure to fluctuations between the
U.S./Canadian dollar exchange rate by matching a significant portion of its
expected cash costs and cash revenues in the same currency. Provident may use
derivative instruments to effectively convert cash flows from U.S. dollars to
Canadian dollars.

In 2003, despite a bullish commodity price environment, the
18 percent appreciation of the Canadian dollar relative to the U.S. dollar over
the year generally had a negative effect on the oil and natural gas sector.
During 2003, the U.S./Canadian dollar exchange rate averaged $0.714 compared to
$0.637 in 2002. Given Canadian currency-denominated 2003 heavy oil hedges,
Provident realized a $2 million positive cash flow increase.

> Interest Rate Risk

Provident is also exposed to fluctuations in the Canadian
prime interest rate as a result of the use of its term revolving debt facility.
Provident actively monitors interest rates and the tools available to
effectively fix interest payable at current or lower rates.

> Credit Risk

Credit risk is the risk of non-payment by a customer or
counterparty. Provident's credit policy has determined portfolio limits to
ensure a diversified customer base and mitigate counterparty exposure. Provident
evaluates the business and financial risk factors for each counterparty through
internal credit procedures and in certain situations may request credit support
in the form of letters of credit, guarantee or cash prepayment. A maximum credit
limit is determined for each counterparty based on the credit ratings and
internal models for each counterparty, which are based on company specific
information and industry analysis. Credit exposures and limits are monitored
routinely and reported to the RMC.

> Insurance

Provident continually reviews its insurance requirements and policies to
ensure adequate coverage of its assets. Insurance is in place for property
damage, general liability, environmental impact, business

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interruption, directors and officers. The RMC receives reports and monitors
the adequacy and appropriateness of Provident's insurance coverage.

The following table summarizes the current Program as at December 31, 2003:

|Year |  | Product             |  | Volume      |  | Terms                                     |  | Effective Period           
|---- |  | ------------------- |  | ----------- |  | ----------------------------------------- |  | ---------------------------
|2004 |  | Light
    Oil       |  | 4,500 Bpd   |  | WTI
    US$23.41 per bbl                  |  | January
    1 - December 31
|     |  |                     |  | 500 Bpd     |  | WTI
    US$25.08 per bbl                  |  | January
    1 - March 31   
|2005 |  | Light
    Oil       |  | 2,000 Bpd   |  | WTI
    US$25.01 per bbl                  |  | January
    1 - December 31
|2004 |  | Heavy
    Oil (1)   |  | 2,800 Bpd   |  | US$17.96 per bbl at Hardisty              |  | January
    1 - December 31
|2004 |  | Natural
    Gas (2) |  | 5,000 Gjpd  |  | Cdn$4.95 per gj                           |  | January
    1 - December 31
|     |  |                     |  | 9,000 Gjpd  |  | Cdn$6.36 per gj                           |  | January
    1 - March 31   
|     |  |                     |  | 900 Gjpd    |  | Cdn$5.75 per gj                           |  | January
    1 - October 31 
|     |  |                     |  | 27,000 Gjpd |  | Cdn$5.10 per gj                           |  | April 1
    - October 31   
|     |  |                     |  | 3,600 Gjpd  |  | Cdn$5.82 per gj                           |  | November 1 - December 31   
|     |  |                     |  | 10,000 Gjpd |  | Funded
    Collar Cdn$5.50 - $8.75 per gj |  | January
    1 - March 31   
|     |  |                     |  | 10,000 Gjpd |  | Costless collar Cdn$5.50 - $7.85 per gj   |  | January
    1 - March 31   
|     |  |                     |  | 5,000 Gjpd  |  | Costless collar Cdn$6.00 - $7.28 per gj   |  | January
    1 - March 31   
|     |  |                     |  | 5,000 Gjpd  |  | Costless collar Cdn$6.25 - $8.00 per gj   |  | January
    1 - March 31   
|     |  |                     |  | 3,000 Gjpd  |  | Costless collar Cdn$5.50 - $6.23 per gj   |  | April 1
    - December 31  
|     |  |                     |  | 3,000 Gjpd  |  | Costless collar Cdn$5.25 - $7.10 per gj   |  | November 1 - December 31   
|     |  |                     |  | 2,000 Gjpd  |  | Costless collar Cdn$5.50 - $7.29 per gj   |  | November 1 - December 31   
|2005 |  | Natural
    Gas (2) |  | 3,000 Gjpd  |  | Cdn$5.90 per gj                           |  | January
    1 - March 31   
|     |  |                     |  | 600 Gjpd    |  | Cdn$5.39 per gj                           |  | January
    1 - October 31 
|     |  |                     |  | 3,000 Gjpd  |  | Costless collar Cdn$5.25 - $7.10 per gj   |  | January
    1 - March 31   
|     |  |                     |  | 2,000 Gjpd  |  | Costless collar Cdn$5.50 - $7.29 per gj   |  | January
    1 - March 31   

Notes:

(1)     The heavy oil price of US$17.96 per
bbl has been fixed through a combination of U.S. dollar denominated WTI
contracts combined with US dollar differential contracts. 
(2)     Natural gas contracts are settled against AECO
monthly index.

OIL AND NATURAL GAS OPERATIONS

Principal Properties

The following are descriptions of Provident's principal producing areas. All
conversions of gas to oil are on a 6:1 basis.

> West Central Alberta

The core operating area of West Central
Alberta accounted for approximately 38 percent of Provident's 2003
production and is Provident's largest production area. Provident believes the
strength of the West Central Alberta region lies in its liquids-rich, longlife
natural gas reserves and high-quality light crude oil.

In the fourth quarter 2003, West Central Alberta production
included 43,308 mcfd (7,218 boed) of natural gas and 2,376 boed of light/medium
oil. In 2003, Provident spent $5.3 million in the region, including $0.9 million
on drilling related expenditures, $0.5 million on workovers, $3.5 million on
optimization projects, and $0.4 million on land and seismic activities.
Operating costs in this area averaged $6.91 per boe in 2003.

- 36 -

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In 2004, production is expected to average 37,800 mcfd (6,300
boed) natural gas and 2,000 boed light/medium oil. With total production
anticipated to be 8,300 boed, West Central Alberta will remain Provident's
top-producing region. Capital expenditures are budgeted at approximately $11.0
million, of which $9.2 million will relate to non-operated activities and $1.8
million on internal projects and related items.

> Lloydminster

The Lloydminster region
accounted for approximately 27 percent of Provident's 2003 production.
Fourth-quarter production was 7,152 boed of heavy oil and 2,310 mcfd (385 boed)
of natural gas. Regarded as the heavy oil capital of the world, Lloydminster has
been a core operating region for Provident since 2001, given its low-risk
development and stable production profile.

Provident posted very strong results on its $12.2 million
development program at Lloydminster, achieving low-risk, flat-profile production
additions at approximately one-third the cost of industry crude oil acquisitions
in 2003. On-stream costs at Lloydminster averaged $8,800 per flowing barrel of
reserves. Provident's Lloydminster heavy oil development program produced an
incremental 2,650 boed, representing 85 percent of Provident's replacement
production in 2003. Operating costs for heavy oil averaged $8.02 per boe in
2003.

Provident continues to apply technical and operating
expertise to its heavy oil properties. Capital expenditures are targeted at
adding inexpensive production or reducing operating costs to maximize netbacks.
In 2004, Provident will allocate $9.4 million of capital to development and
optimization activities in the Lloydminster region, $5.5 million of this amount
will be spent on low-risk drilling opportunities, $2.5 million on land
acquisition and seismic evaluation, and $1.4 million on workovers and related
items. Annual production is expected to be approximately 6,440 boed of heavy oil
and 1,900 mcfd (300 boed) of natural gas.

> Southern Alberta

The Southern Albertaregion
accounted for approximately 22 percent of 2003 average production. The region
consists of 12 operated and non-operated properties that were acquired in three
separate transactions in 2002. In the fourth quarter of 2003 natural gas
production averaged 19,947 mcfd (3,325 boed), while light/medium oil and NGLs
were 2,176 boed. Provident spent $6.6 million in 2003, including $2.6 million
for drilling and $3.2 million on recompletion and optimization. Provident added
an incremental 550 boed of light/medium oil production in Southern Alberta
through internal development efforts in 2003. On stream costs were $12,000 per
boe flowing. Operating costs in this area averaged $8.59 per boe.

In 2004, Provident intends to spend approximately $10 million
in the Southern Alberta region, primarily on shallow natural gas-related
opportunities. Provident expects to spend $6.3 million on drilling-related
activities and the balance on facilities, land and seismic evaluation.
Production is expected to average 19,800 mcfd (3,300 boed) of natural gas and
2,200 boed of light/medium oil and NGLs for 2004.

> Southwest Saskatchewan

Southwest Saskatchewan accounted for
approximately 6 percent of Provident's 2003 production. The region was added to
Provident's core operating areas following the acquisition of Meota in 2002.

Fourth quarter production included 1,118 boed of light/medium oil and NGLs
and 2,902 mcfd (484 boed) of natural gas. Production in this core area has lower
declines in the predominantly shallow natural-gas

- 37 -

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formations. In 2003, Provident spent $1.5 million in the
region, including drilling-related activities, facilities, land acquisition and
retention, and seismic evaluation. Operating costs in the area averaged $7.42
per boe.

Due to Southwest Saskatchewan's significant low-risk infill
drilling and shallow natural gas development potential, Provident intends to
spend approximately $12 million, 27 percent of its capital budget, on shallow
gas development in 2004. The region's 2004 shallow gas capital program includes
$9.5 million on drilling and the remainder on land acquisition and seismic
evaluation. 2004 production is expected to average approximately 2,000 boed,
including 6,000 mcfd (1,000 boed) of natural gas and 1,000 boed of light/medium
oil and NGLs.

Southeast Saskatchewan

Provident's Southeast Saskatchewan region accounted for
approximately 7 percent of 2003 production. Located on the northern edge of the
Williston Basin, Provident's high working interests in this region contribute
stable, light/medium oil production.

Fourth quarter 2003 production averaged 1,961 boed. Annual
operating costs averaged $7.48 per boe. In 2003, Provident spent $2.3 million in
the region, approximately 50 percent of which was spent on drilling-related
activities and the remainder on workovers and facilities.

Production is expected to average 1,600 boed in 2004. Provident intends to
spend approximately $2.8 million on capital projects, including $1.8 million to
be spent on drilling prospects.

Reserves and Future Net Revenue

The following is a summary of the oil and natural gas
reserves and the value of future net revenue of Provident as evaluated by
McDaniel in the McDaniel Report. The pricing used in the forecast and constant
price evaluations is set forth in the notes to the tables.

All evaluations of future revenue are after the deduction of
royalties, development costs, production costs and well abandonment costs but
before consideration of indirect costs such as administrative, overhead and
other miscellaneous expenses. The estimated future net revenue contained in the
following tables do not necessarily represent the fair market value of the
Corporation's reserves. There is no assurance that the forecast price and cost
assumptions contained in the McDaniel Report will be attained and variances
could be material. Other assumptions and qualifications relating to costs and
other matters are included in the McDaniel Report. The recovery and reserves
estimates on Provident's properties described herein are estimates only. The
actual reserves on Provident's properties may be greater or less than those
calculated.

OIL AND GAS RESERVES 
BASED ON CONSTANT PRICES AND COSTS(9)

|                                         | Light and Medium Oil | Heavy Oil | Natural Gas | Natural Gas Liquids
|---------------------------------------- | -------------------- | --------- | ----------- | -------------------
|                                         | Gross(1)             | Net(1)    | Gross(1)    | Net(1)             
|                                         | (mbbl)               | (mbbl)    | (mbbl)      | (mbbl)             
|Proved
    Developed Producing(2)(6)     | 11,760               | 10,051    | 4,065       | 3,483              
|Proved
    Developed Non-Producing(2)(7) | 227                  | 184       | 514         | 442                
|Proved
    Undeveloped(2)(8)             | 346                  | 296       | 3,062       | 2,748              
|                                         |                      |           |             |                    
|Total
    Proved(2)                      | 12,333               | 10,530    | 7,640       | 6,672              

- 38 -

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NET PRESENT VALUES OF FUTURE NET REVENUE 
BASED ON CONSTANT PRICES AND COSTS(9)

|                                         | 0%      | 10%    
|---------------------------------------- | ------- | -------
|                                         | (M$)    | (M$)   
|Proved
    Developed Producing(2)(6)     | 594,257 | 417,203
|Proved
    Developed Non-Producing(2)(7) | 24,584  | 16,120 
|Proved
    Undeveloped(2)(8)             | 29,484  | 18,582 
|Total
    Proved(2)                      | 648,325 | 451,904

After tax forecasts not applicable as Provident is an energy trust.

TOTAL FUTURE NET REVENUE 
(UNDISCOUNTED) 
BASED ON CONSTANT PRICES AND COSTS(9)

|                |         |           |           |             |             | Future          |        | Future          
|--------------- | ------- | --------- | --------- | ----------- | ----------- | --------------- | ------ | ----------------
|                |         |           |           |             | Abandonment | Net
    Revenue |        | Net             
|                |         |           |           |             | and         | Before          |        | Revenue         
|                |         |           | Operating | Development | Reclamation | Income          | Income | After
    Income
|                | Revenue | Royalties | Costs     | Costs       | Costs       | Taxes           | Taxes  | Taxes           
|                | (MM$)   | (MM$)     | (MM$)     | (MM$)       | (MM$)       | (MM$)           | (MM$)  | (MM$)           
|                |         |           |           |             |             |                 |        |                 
|Total Proved(2) | 1,417.9 | 272.9     | 415.2     | 24.7        | 56.8        | 648.3           | N/A    | N/A             

FUTURE NET REVENUE BY PRODUCTION GROUP 
BASED UPON CONSTANT PRICES AND COSTS(9)

|                |                                       | Future Net Revenue Before Income  
|--------------- | ------------------------------------- | ----------------------------------
|                |                                       | Taxes
    (Discounted at 10%/Year)
|                | Production Group                      | (M$)                              
|Total Proved(2) | Light and medium crude oil            | 141,078.8                         
|                | Heavy oil                             | 38,829.8                          
|                | Associated gas and non-associated gas | 284,625.4                         

OIL AND GAS RESERVES 
BASED ON FORECAST PRICES AND COSTS(10)

|                                         | Light and Medium Oil | Heavy Oil | Natural Gas | Natural Gas Liquids
|---------------------------------------- | -------------------- | --------- | ----------- | -------------------
|                                         | Gross(1)             | Net(1)    | Gross(1)    | Net(1)             
|                                         | (mbbl)               | (mbbl)    | (mbbl)      | (mbbl)             
|Proved Developed
    Producing(2)(6)     | 11,155               | 9,545     | 3,937       | 3,372              
|Proved Developed
    Non-Producing(2)(7) | 226                  | 187       | 508         | 439                
|Proved Undeveloped(2)(8)                 | 346                  | 297       | 3,028       | 2,746              
|Total Proved(2)                          | 11,727               | 10,028    | 7,473       | 6,557              
|Total Probable(3)                        | 3,183                | 2,719     | 4,402       | 3,963              
|Total Proved Plus
    Probable(2)(3)     | 14,910               | 12,747    | 11,876      | 10,520             

- 39 -

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NET PRESENT VALUES OF FUTURE NET REVENUE 
BASED ON FORECAST PRICES AND COSTS(10)

|                                         |         | Before Deducting Income Taxes
    Discounted At(1) |        
|---------------------------------------- | ------- | -------------------------------------------------- | -------
|                                         | 0%      | 5%                                                 | 10%    
|                                         | ($M)    | ($M)                                               | ($M)   
|Proved Developed
    Producing(2)(6)     | 439,686 | 366,368                                            | 322,198
|Proved Developed
    Non-Producing(2)(7) | 9,603   | 9,443                                              | 8,765  
|Proved Undeveloped(2)(8)                 | 19,993  | 15,504                                             | 12,152 
|Total Proved(2)                          | 469,282 | 391,613                                            | 343,114
|Total Probable(3)                        | 150,305 | 100,534                                            | 75,140 
|Total Proved Plus
    Probable(2)(3)     | 619,588 | 491,850                                            | 418,254

(1) After tax forecasts not applicable as Provident is an energy trust.

TOTAL FUTURE NET REVENUE 
(UNDISCOUNTED) 
BASED ON FORECAST PRICES AND COSTS(10)

|                  |         |           |           |             |             |                 |        |                 
|----------------- | ------- | --------- | --------- | ----------- | ----------- | --------------- | ------ | ----------------
|                  |         |           |           |             |             | Future          |        | Future          
|                  |         |           |           |             | Abandonment | Net
    Revenue |        | Net             
|                  |         |           |           |             | and         | Before          |        | Revenue         
|                  |         |           | Operating | Development | Reclamation | Income          | Income | After
    Income
|                  | Revenue | Royalties | Costs     | Costs       | Costs       | Taxes           | Taxes  | Taxes           
|                  | (MM$)   | (MM$)     | (MM$)     | (MM$)       | (MM$)       | (MM$)           | (MM$)  | (MM$)           
|                  |         |           |           |             |             |                 |        |                 
|Total Proved(2)   | 1,242.5 | 233.4     | 447.9     | 25.0        | 66.9        | 469.3           | N/A    | N/A             
|Total Proved Plus | 1,606.0 | 295.2     | 575.2     | 45.3        | 70.8        | 619.6           | N/A    | N/A             
|Probable(2)(3)    |         |           |           |             |             |                 |        |                 

FUTURE NET REVENUE BY PRODUCTION GROUP 
BASED ON FORECAST PRICES AND COSTS(9)

|                |                                           | Future Net Revenue Before Income Taxes
|--------------- | ----------------------------------------- | --------------------------------------
|                |                                           | (Discounted at 10%/Year)              
|                | Production Group                          | (M$)                                  
|Total Proved(2) | Light and medium crude oil                | 94,024.0                              
|                | Heavy oil                                 | 31,432.0                              
|                | Associated gas and
    non-associated gas | 230,335.4                             

RECONCILIATION OF COMPANY NET 
RESERVES BY PRINCIPAL PRODUCT TYPE 
BASED ON FORECAST PRICES AND COSTS (10)

The following table sets forth a reconciliation of the
changes in Provident's light and medium crude oil, heavy oil and associated and
non-associated gas (combined) reserves as at December 31, 2003 against such
reserves as at December 31, 2002 based on the price and cost assumptions set
forth in note 10.

|                        |          | Light & Medium Oil |                | Heavy Oil |          | Associated & Non Associated Gas
|----------------------- | -------- | ------------------ | -------------- | --------- | -------- | -------------------------------
|                        |          |                    |                |           |          | Net                            
|                        |          |                    | Net
    Proved |           |          | Proved                         
|                        | Net      | Net                | Plus           | Net       | Net      | Plus                           
|                        | Proved   | Probable           | Probable       | Proved    | Probable | Probable                       
|                        | (mbbl)   | (mbbl)             | (mbbl)         | (mbbl)    | (mbbl)   | (mbbl)                         
|                        |          |                    |                |           |          |                                
|At December 31, 2002    | 14,692.9 | 2,150.8            | 16,843.7       | 8,422.5   | 2,751.1  | 11,173.6                       
|Extensions              | 64.3     | 16.1               | 80.4           | 609.2     | 102.6    | 711.8                          
|Improved
    Recovery   | -        | -                  | -              | -         | -        | -                              
|Technical
    Revisions | -288.6   | 982.2              | 693.6          | -282.2    | 1,093.4  | 811.2                          
|Discoveries             | -        | -                  | -              | -         | -        | -                              
|Acquisitions            | 0.2      | -                  | 0.2            | -         | -        | -                              

- 40 -

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|                     | Light & Medium Oil |          | Heavy Oil      |          | Associated & Non Associated Gas
|-------------------- | ------------------ | -------- | -------------- | -------- | -------------------------------
|                     |                    |          |                |          |                                
|                     |                    |          | Net
    Proved |          |                                
|                     | Net                | Net      | Plus           | Net      | Net                            
|                     | Proved             | Probable | Probable       | Proved   | Probable                       
|                     | (mbbl)             | (mbbl)   | (mbbl)         | (mbbl)   | (mbbl)                         
|Dispositions         | -233.4             | -56.1    | -289.5         | -        | -                              
|Economic Factors     | -125.4             | 47.8     | -77.6          | -75.1    | 15.7                           
|Production           | -2,336.0           | -        | 2,336.0        | -2,117.0 | 0.0                            
|At December 31, 2003 | 11,774.0           | 3,140.7  | 14,914.7       | 6,557.4  | 3,962.8                        
|                     |                    |          |                |          |                                

The following table sets forth changes between future net revenue estimates
attributable to net proved reserves as at December 31, 2003 against such
reserves as at December 31, 2003.

RECONCILIATION OF CHANGES IN NET PRESENT VALUES OF FUTURE
  NET REVENUE 
  DISCOUNTED AT 10% 
  BASED ON CONSTANT PRICES AND COSTS (9)

|                                                                                          | 2003     
|----------------------------------------------------------------------------------------- | ---------
|                                                                                          | (M$)     
|                                                                                          |          
|Estimated Future Net
    Revenue at December 31, 2002                                     | 789,559  
|Sales and
    Transfers of Oil and Gas Produced, Net of Production Costs and Royalties    | (198,481)
|Net
    Change in Prices, Production Costs and Royalties Related to Future
    Production | (108,275)
|Changes
    in Previously Estimated Future Development Costs                              | (11,836) 
|Changes
    in Estimated Future Development Costs                                         | (5,983)  
|Extensions and Improved Recovery                                                          | 8,759    
|Discoveries                                                                               | -        
|Acquisitions of Reserves                                                                  | 34       
|Dispositions of Reserves                                                                  | (15,082) 
|Net
    Change Resulting from Revisions in Quantity Estimates                             | (31,826) 
|Accretion
    of Discount                                                                 | 25,035   
|Net
    Change in Income Taxes                                                            | N/A      
|Estimated Future Net
    Revenue at December 31, 2003                                     | 451,904  

Notes:

1. "Gross Reserves" are Provident's working interest (operating
  or non-operating) share before deducting of royalties and without including
  any royalty interests of Provident. "Net Reserves" are Provident's working
  interest (operating or non-operating) share after deduction of royalty
  obligations, plus Provident's royalty interests in reserves.
2. "Proved" reserves are those reserves that can be estimated
  with a high degree of certainty to be recoverable. It is likely that the
  actual remaining quantities recovered will exceed the estimated proved
  reserves.
3. "Probable" reserves are those additional reserves that are
  less certain to be recovered than proved reserves. It is equally likely that
  the actual remaining quantities recovered will be greater or less than the sum
  of the estimated proved plus probable reserves.
4. "Possible" reserves are those additional reserves that are
  less certain to be recovered than probable reserves. It is unlikely that the
  actual remaining quantities recovered will exceed the sum of the estimated
  proved plus probable plus possible reserves.
5. "Developed" reserves are those reserves that are expected to
  be recovered from existing wells and installed facilities or, if facilities
  have not been installed, that would involve a low expenditure (e.g. when
  compared to the cost of drilling a well) to put the reserves on production.
6. "Developed Producing" reserves are those reserves that are
  expected to be recovered from completion intervals open at the time of the
  estimate. These reserves may be currently producing or, if shut-in, they must
  have previously been on production, and the date of resumption of production
  must be known with reasonable certainty.
7. "Developed Non-Producing" reserves are those reserves that
  either have not been on production, or have previously been on production, but
  are shut in, and the date of resumption of production is unknown.
8. "Undeveloped" reserves are those reserves expected to be
  recovered from know accumulations where a significant expenditure (for
  example, when compared to the cost of drilling a well) is required to render
  them capable of production. They must fully meet the requirements of the
  reserves classification (proved, probable, possible) to which they are
  assigned.
9. The product prices used in the constant price and cost
  evaluations in the McDaniel Report were as follows: Light/Medium Crude $Cdn
  $40.93/bbl; Heavy Crude $Cdn 32.00/bbl; Natural Gas $Cdn 5.99/mcf; Natural Gas
  Liquids $Cdn 38.14/bbl.

The pricing
  assumptions used in the McDaniel Report with respect to net values of future
  net revenue (forecast) as well as the inflation rates used for operating and
  capital costs are set forth below. McDaniel is an independent qualified
  reserves evaluator appointed pursuant to NI 51-101.

- 41 -

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|                               |                            |               |                  |                  |                |               |        |         
|------------------------------ | -------------------------- | ------------- | ---------------- | ---------------- | -------------- | ------------- | ------ | --------
|                               |                            |               |                  |                  |                |               |        |         
|                               |                            |               |                  |                  |                | Natural Gas   |        |         
|                               | Light and Medium Crude Oil | Heavy Oil     | Natural Gas      | Liquids          | Inflation Rate | Exchange Rate
|                               |                            | Edmonton      | Cromer           |                  |                |               |        |         
|                               | WTI
    Cushing            | Par
    Price | Medium
    29.30 | Hardisty         | AECO
    Gas   | Edmonton      |        |         
|                               | Oklahoma                   | 400API        | API              | Heavy
    120API | Price          | NGL
    Mix   |        |         
|                               | ($US/bbl)                  | ($Cdn/bbl)    | ($Cdn/bbl)       | ($Cdn/bbl)       | ($Cdn/mmbtu)   | ($Cdn/bbl)    | %/year | $US/$Cdn
|                               |                            |               |                  |                  |                |               |        |         
|Year                           |                            |               |                  |                  |                |               |        |         
|Forecast                       |                            |               |                  |                  |                |               |        |         
|2004                           | 29.00                      | 37.70         | 32.20            | 22.70            | 5.50           | 27.90         | 2.0    | 0.750   
|2005                           | 26.50                      | 34.30         | 29.71            | 21.55            | 5.19           | 25.50         | 2.0    | 0.750   
|2006                           | 25.50                      | 33.00         | 28.84            | 21.56            | 4.87           | 24.50         | 2.0    | 0.750   
|2007                           | 25.00                      | 32.30         | 28.06            | 20.63            | 4.68           | 23.80         | 2.0    | 0.750   
|2008                           | 25.00                      | 32.30         | 27.97            | 20.39            | 4.53           | 23.70         | 2.0    | 0.750   
|Thereafter
    escalated at 2% |                            |               |                  |                  |                |              

Undeveloped Reserves

The following table sets forth the volumes of proved undeveloped reserves
that were attributed for each of Provident's product types for the most recent
five financial years and in the aggregate before that time.

|Proved Undeveloped       | Light
    and Medium |               |             |                    
|------------------------ | -------------------- | ------------- | ----------- | -------------------
|                         | Oil                  | Heavy
    Oil | Natural Gas | Natural Gas Liquids
|                         | (mbbl)               | (mbbl)        | (mmcf)      | (mbbl)             
|2001                     | 229.8                | 4,286.8       | 4,924.2     | 121.5              
|2002                     | 329.6                | 3,775.1       | 3,495.0     | 47.7               
|2003                     | 155.0                | 2,745.1       | 1,774.2     | 39.0               
|                         |                      |               |             |                    
|Probable
    Undeveloped | Light
    and Medium |               |             |                    
|                         | Oil                  | Heavy
    Oil | Natural Gas | Natural Gas Liquids
|                         | (mbbl)               | (mbbl)        | (mmcf)      | (mbbl)             
|2001                     | 512.1                | 3,849.8       | 5,873.0     | 208.9              
|2002                     | 121.2                | 3,438.7       | 2,381.5     | 42.1               
|2003                     | 228.3                | 3,180.9       | 832.4       | 11.7               

Provident's proved undeveloped and probable undeveloped
reserves are attributed in accordance with NI 51-101, the majority of which are
represented by heavy oil locations in the Lloydminster area of Alberta. These
reserves are expected to be developed over the following 2 to 4 years. The basis
for this time frame is that the undeveloped locations are developed with the
purpose of replacing naturally occurring production declines, and not in an
effort to bring the production on stream all at once.

Future Development Costs

FUTURE DEVELOPMENT COSTS

|                                               | Total
    Proved Estimated | Total
    Proved         | Total
    Proved Plus    
|---------------------------------------------- | -------------------------- | ------------------------ | -------------------------
|                                               | Using                      | Estimated Using Forecast | Probable Estimated Using 
|                                               | Constant Prices and Costs  | Prices and Costs         | Forecast Prices and Costs
|                                               | (M$)                       | (M$)                     | (M$)                     
|2004                                           | 8,200                      | 8,200                    | 11,200                   
|2005                                           | 10,800                     | 10,900                   | 22,600                   
|2006                                           | 5,200                      | 5,400                    | 10,000                   
|2007                                           | 100                        | 100                      | 700                      
|2008                                           | -                          | -                        | 100                      
|Total for all years
    undiscounted           | 24,700                     | 22,500                   | 45,300                   
|Total for all years
    discounted at 10%/year | 22,000                     | 22,200                   | 39,800                   

Provident will use a combination of funding sources for
future development costs including; internally generated cash flow, debt and
equity financing including dividend re-investment programs and other equity
issues. The cost of these funds is not expected to have a material or
significant impact on disclosed reserves.

- 42 -

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Significant Factors or Uncertainties

There are no significant factors or uncertainties that may
impact the reserves and values other than those general factors relating to the
oil and gas business in general and as discussed in this section, the
Management's Discussion and Analysis incorporated by reference herein, and
elsewhere in this Annual Information Form.
Oil and Gas Properties and Wells

The following table sets forth the number of wells in which Provident held a
working interest as at December 31, 2003:

|                       |       | Producing Wells |       | Non-Producing Wells |      
|---------------------- | ----- | --------------- | ----- | ------------------- | -----
|                       | Oil   | Natural Gas     | Oil   | Natural Gas        
|                       | Gross | Net             | Gross | Net                 | Gross
|Alberta                |       |                 |       |                     |      
|Lloydminster           | 215   | 211.7           | 4     | 0.9                 | 96   
|West Central Alberta   | 528   | 69.4            | 354   | 131.1               | 170  
|Southern Alberta       | 347   | 206.6           | 679   | 313.3               | 219  
|Other Alberta          | 173   | 14.2            | 164   | 38.7                | 72   
|                       | 1,263 | 501.9           | 1,201 | 484.0               | 557  
|Saskatchewan           |       |                 |       |                     |      
|Lloydminster           | 165   | 160.4           | 11    | 11                  | 37   
|Southeast Saskatchewan | 970   | 184             | 1     | 0.3                 | 112  
|Southwest Saskatchewan | 130   | 75.9            | 43    | 42.1                | 8    
|Other Saskatchewan     | 2     | 2               | 1     | 1                   | 0    
|                       | 1,267 | 422.3           | 56    | 54.4                | 157  
|                       |       |                 |       |                     |      
|British Columbia       | 74    | 4.7             | 169   | 1                   | 100  
|                       |       |                 |       |                     |      
|                       |       |                 |       |                     |      
|Total                  | 2,604 | 928.9           | 1,430 | 539.4               | 814  

(1) "Gross" wells mean the number of wells in which Provident has an
interest. 
(2) "Net" wells means the aggregate numbers obtained by multiplying each gross
well by Provident's percentage interest therein.

Significant Properties

The following outlines Provident's top 5 most significant
properties based upon present worth value and forecast prices and costs.
Virtually all of Provident's properties are located onshore in Canada. The
individual value of each of these properties would not exceed 10% of the total
value of the company's reserves on a proved basis. Undeveloped reserves for
these properties are not significant with the exception of Lloydminster which
has been discussed previously.

Brazeau River and Whitecourt are gas properties located in west central
Alberta.

Lloydminster is a collection of heavy oil properties in
eastern Alberta. The undeveloped reserves attributed to Lloydminster will be
developed on the basis of single well batteries and the timing of their
development is solely a matter of timing to replace current production declines.

Gilby is an oil and gas property in central Alberta.

Little Bow is an oil and gas property in Southern Alberta.

Costs Incurred

The following table summarizes the capital expenditures made by Provident on
oil and natural gas properties for the year ended December 31, 2003.

- 43 -

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|Property
    Acquisition Costs | Exploration Costs | Development Costs
|------------------------------ | ----------------- | -----------------
|(M$)                           | (M$)              | (M$)             
|                               | Unproved          |                  
|Proved Properties              | Properties        |                  
|159                            | -                 | -                
|159                            | -                 | -                

Exploration and Development Activities

The following table sets forth the number of exploratory and development
wells which Provident completed during its 2003 financial year:

|                  | Exploratory Wells | Development Wells
|----------------- | ----------------- | -----------------
|                  | Gross(1)          | Net(1)           
|                  |                   |                  
|Oil
    Wells     | -                 | -                
|Gas
    Wells     | -                 | -                
|Service
    Wells | -                 | -                
|Dry
    Holes     | -                 | -                
|                  | -                 | -                

Note:

(1) "Gross Reserves" are Provident's working interest
(operating or non-operating) share before deducting of royalties and without
including any royalty interests of Provident. "Net Reserves" are Provident's
working interest (operating or non-operating) share after deduction of royalty
obligations, plus Provident's royalty interests in reserves.

Abandonment and Reclamation Costs

Abandonment and reclamation costs for well bores and surface
leases are estimated by McDaniel & Associates based upon operating practices and
experience. Plant and other facility abandonment and reclamation costs are
assumed to be offset by facility salvage costs. The future net present values
disclosed herein are after abandonment costs. Provident expects to abandon 2,009
net wells in total over the life of the reserves.

The expected abandonment costs for each of the next three years and over the
life of the reserves is shown below, both undiscounted and discounted at 10%
based on constant prices and costs.

|                       | Abandonment Costs
|---------------------- | -----------------
|                       | Undiscounted - M$
|2004                   | 2,200            
|2005                   | 3,500            
|2006                   | 4,000            
|3 year Subtotal        | 9,700            
|                       |                  
|Total Undiscounted     | 59,000           
|                       |                  
|Total Discounted @ 10% | 28,900           

Production Estimates

The following table sets forth the volume of production estimated for 2004
(company interest including royalty volumes earned:

- 44 -

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|        | Light and Medium Oil | Heavy Oil    | Natural Gas  | Natural Gas Liquids
|------- | -------------------- | ------------ | ------------ | -------------------
|Total   | 2,310.9 mbbl         | 2,147.1 mbbl | 23,500 mbbl  | 246.4 mbbl         
|Per Day | 6,331 bbls/d         | 5.882 bbls/d | 64,383 mcf/d | 675 bbls/d         
|        |                      |              |              |                    

Production History

The following table sets forth certain information in respect
of production, product prices received, including hedging activities, royalties,
production costs and netbacks received by the Corporation for each quarter of
its most recently completed financial year:

|                                  | Three
    Months Ended | Three
    Months Ended | Three
    Months Ended | Three
    Months Ended
|--------------------------------- | ---------------------- | ---------------------- | ---------------------- | ----------------------
|                                  | March 31, 2003         | June 30, 2003          | September 30, 2003     | December 31, 2003     
|Average Daily
    Production      |                        |                        |                        |                       
|Light and
    Medium Oil (mbbl/d) | 7,285                  | 6,770                  | 6,748                  | 6,454                 
|Heavy Oil
    (mbbl/d)            | 6,245                  | 6,700                  | 7,495                  | 7,151                 
|Natural
    Gas (mcf/d)           | 83,924                 | 72,898                 | 73,090                 | 68,657                
|Natural
    Gas Liquids (mbbl/d)  | 1,085                  | 1,162                  | 1,276                  | 1,145                 
|Average Net Prices
    Received   |                        |                        |                        |                       
|Light and
    Medium Oil ($/mbbl) | $ 43.64                | $ 33.57                | $ 33.49                | $ 32.79               
|Heavy Oil
    ($/mbbl)            | 31.63                  | 23.47                  | 24.17                  | 20.61                 
|Natural
    Gas ($/mcf)           | 7.94                   | 5.64                   | 5.14                   | 5.62                  
|Natural
    Gas Liquids ($/mbbl)  | 45.13                  | 37.16                  | 28.26                  | 34.48                 
|Royalties                         |                        |                        |                        |                       
|Light and
    Medium Oil ($/bbl)  | $ 9.37                 | $ 6.55                 | $ 6.85                 | $ 6.70                
|Heavy Oil
    ($/bbl)             | 4.48                   | 3.87                   | 4.88                   | 3.80                  
|Natural
    Gas ($/mcf)           | 1.81                   | 1.56                   | 1.18                   | 1.15                  
|Natural
    Gas Liquids ($/bbl)   | 16.55                  | 11.12                  | 7.19                   | 8.43                  
|Production Costs                  |                        |                        |                        |                       
|Light and
    Medium Oil ($/bbl)  | $ 7.70                 | $ 7.59                 | $ 8.62                 | $ 10.29               
|Heavy Oil
    ($/bbl)             | 8.26                   | 9.39                   | 7.86                   | 8.02                  
|Natural
    Gas ($/mcf)           | 0.96                   | 1.08                   | 1.11                   | 1.48                  
|Natural
    Gas Liquids ($/bbl)   | 5.74                   | 6.47                   | 6.66                   | 8.87                  
|Netback Received                  |                        |                        |                        |                       
|Light and
    Medium Oil ($/bbl)  | $ 14.97                | $ 15.04                | $ 12.77                | $ 9.63                
|Heavy Oil
    ($/bbl)             | 11.61                  | 8.66                   | 9.42                   | 8.44                  
|Natural
    Gas ($/mcf)           | 3.69                   | 3.20                   | 2.82                   | 2.87                  
|Natural
    Gas Liquids ($/bbl)   | 22.83                  | 19.56                  | 14.41                  | 17.17                 

MIDSTREAM NGL PROCESSING 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 the Midstream NGL
Assets represent 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% of NGLs are a by-product of natural gas processing,
with 10% resulting from the refining of crude oil. Approximately 75% 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.

- 45 -

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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% of propane and 80% 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%
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 western 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 western 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 smaller amount
of the NGLs movement transported in Alberta, with pipelines serving as the main
mode of transport.

- 46 -

---

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 Alberta are located in 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% 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% of
Canadian propane is exported to the US.
Butane, which makes up approximately 25% of propane-plus
produced in major extraction facilities, is used primarily in gasoline blending
or in the production of Canadian iso-octane. Approximately 25% of Canadian
butane is exported to the US.
Pentanes-plus, which represents less than 10% 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 this purpose.Commercial Arrangements
ExtractionAn 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%
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
- 47 -

---

NGLs. Other expenses include electrical power, labour, maintenance, property
taxes, insurance and other overhead.
For ethane, market prices usually consist of a shrinkage gas
cost which flows through to ethane buyers, 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).
SELECTED CONSOLIDATED FINANCIAL INFORMATION

The following selected consolidated financial information was
prepared in accordance with accounting principles generally accepted in Canada
and highlights trends in Provident's financial condition and results of
operations for the year ended December 31, 2003 and 2002 and for the period
March 6, 2001 to December 31, 2001. Reference is made to the consolidated
financial statements of the Trust contained in the Annual Report of the Trust,
which information is hereby incorporated into this Annual Information Form by
reference. The consolidated financial statements of the Trust contained in the
Annual Report of the Trust are available on SEDAR at www.sedar.com.
- 48 -

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|Annual Information                                       |                 |                 |                 |          |   |         
|-------------------------------------------------------- | --------------- | --------------- | --------------- | -------- | - | --------
|(000s except per
    unit data)                          | 2003 (365 days) | 2002 (365 days) | 2001 (301 days)
|Sales                                                    | $               | 473,571         | $               | 207,823  | $ | 78,311  
|Earnings (loss)                                          |                 | 33,394          |                 | 8,340    |   | (46,622)
|per
    trust unit                                       |                 | 0.38            |                 | 0.09     |   | (3.38)  
|per
    diluted trust unit                               |                 | 0.38            |                 | 0.09     |   | (3.38)  
|Cash flow from
    operations                            |                 | 135,706         |                 | 96,896   |   | 36,228  
|per
    trust unit                                       |                 | 1.98            |                 | 2.41     |   | 2.62    
|Total assets                                             |                 | 1,137,936       |                 | 875,047  |   | 189,959 
|Long-term debt                                           |                 | 236,500         |                 | 187,200  |   | 35,600  
|Working capital
    (deficiency)                         |                 | 18,552          |                 | (15,681) |   | (1,862) 
|Unitholders' equity                                      |                 | 679,228         |                 | 471,420  |   | 104,944 
|Weighted average trust
    units and exchangeable shares |                 | 68,448          |                 | 40,222   |   | 13,813  
|outstanding                                              |                 |                 |                 |          |   |         

Quarterly Information (unaudited)

|(in 000s except per
    unit data) |   | First     |   | Second |   | Third    |   | Fourth  
|---------------------------------- | - | --------- | - | ------ | - | -------- | - | --------
|2003                               |   |           |   |        |   |          |   |         
|Sales                              | $ | 87,888    | $ | 74,015 | $ | 70,532   | $ | 227,210 
|Earnings (loss)                    |   | (8,743)   |   | 23,073 |   | (2,003)  |   | 21,067  
|per
    trust unit                 |   | (0.14)    |   | 0.36   |   | (0.03)   |   | 0.26    
|per
    fully diluted trust unit   |   | (0.14)    |   | 0.36   |   | (0.03)   |   | 0.26    
|Cash flow from
    operations      |   | 41,961    |   | 31,571 |   | 28,866   |   | 33,308  
|per
    trust unit                 |   | 0.69      |   | 0.49   |   | 0.44     |   | 0.41    
|                                   |   |           |   |        |   |          |   |         
|                                   |   | First     |   | Second |   | Third    |   | Fourth  
|2002                               |   |           |   |        |   |          |   |         
|Sales                              | $ | 31,641    | $ | 46,123 | $ | 48,191   | $ | 81,698  
|Earnings (loss)                    |   | 823       |   | 763    |   | (279)    |   | 7,034   
|per
    trust unit                 |   | 0.03      |   | 0.02   |   | (0.01)   |   | 0.12    
|per
    fully diluted trust unit   |   | 0.03      |   | 0.02   |   | (0.01)   |   | 0.12    
|Cash flow from
    operations      |   | 15,324    |   | 22,642 |   | 22,631   |   | 36,299  
|per
    trust unit                 |   | 0.51      |   | 0.63   |   | 0.61     |   | 0.63    
|                                   |   |           |   |        |   |          |   |         
|                                   |   | First (1) |   | Second |   | Third    |   | Fourth  
|2001                               |   |           |   |        |   |          |   |         
|Sales                              |   | 4,946     |   | 21,267 |   | 30,390   |   | 21,708  
|Earnings (loss)                    |   | 883       |   | 3,102  |   | (36,747) |   | (13,860)
|per
    trust unit                 |   | 0.12      |   | 0.31   |   | (2.38)   |   | (0.78)  
|per
    fully diluted trust unit   |   | 0.12      |   | 0.31   |   | (2.38)   |   | (0.78)  
|Cash flow from
    operations      |   | 2,680     |   | 10,597 |   | 13,601   |   | 9,350   
|per
    trust unit                 |   | 0.38      |   | 1.05   |   | 0.88     |   | 0.53    

Note: (1) The first quarter was for the 26 day period from March 6, 2001 to March
31, 2001.

MANAGEMENT'S DISCUSSION AND ANALYSIS

Reference is made to the information under the heading
"Management's Discussion and Analysis" in the Annual Report of the Trust, which
information is hereby incorporated into this Annual Information Form by
reference. The management's discussion and analysis information contained in the
Annual Report of the Trust is available on SEDAR at www.sedar.com.

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 AMEX under the
symbol PVX. The 10.5% Debentures and the 8.75% Debentures of the Trust are
listed and posted for trading on the TSX under the symbol PVE.DB and PVE.DB.A,
respectively.

- 49 -

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The following table summarizes the Trust Unit trading activity for the
periods indicated on both the Toronto Stock Exchange and the American Stock
Exchange:
Toronto Stock Exchange

|Period                  | High           | Low            | Volume (000's)
|----------------------- | -------------- | -------------- | --------------
|2002                    |                |                |               
|First Quarter           | $10.70         | $ 8.20         | 16,563        
|Second Quarter          | $11.33         | $ 9.77         | 11,330        
|Third Quarter           | $11.44         | $10.02         | 11,546        
|Fourth Quarter          | $11.03         | $ 9.85         | 12,524        
|                        |                |                |               
|2003                    |                |                |               
|January                 | $11.29         | $10.60         | 5,353         
|February                | $11.42         | $10.88         | 3,153         
|March                   | $11.95         | $ 9.85         | 10,495        
|April                   | $11.20         | $10.00         | 7,169         
|May                     | $11.72         | $10.71         | 7,773         
|June                    | $12.75         | $10.00         | 10,133        
|July                    | $11.40         | $10.80         | 6,891         
|August                  | $11.83         | $10.80         | 6,442         
|September               | $11.23         | $10.45         | 10,856        
|October                 | $11.25         | $10.50         | 8,776         
|November                | $11.75         | $10.28         | 8,559         
|December                | $11.61         | $10.72         | 4,678         
|                        |                |                |               
|American Stock Exchange |                |                |               
|                        |                |                |               
|Period                  | High           | Low            | Volume (000's)
|2002                    |                |                |               
|First Quarter           | U.S.
    $6.83 | U.S.
    $5.17 | 2,224         
|Second Quarter          | U.S.
    $7.48 | U.S.
    $6.34 | 4,590         
|Third Quarter           | U.S.
    $7.41 | U.S.
    $6.82 | 4,445         
|Fourth Quarter          | U.S.
    $6.97 | U.S.
    $6.86 | 6,597         
|                        |                |                |               
|2003                    |                |                |               
|January                 | U.S.
    $7.26 | U.S.
    $6.95 | 4,772         
|February                | U.S.
    $7.61 | U.S.
    $7.23 | 3,628         
|March                   | U.S.
    $8.06 | U.S.
    $6.65 | 14,227        
|April                   | U.S.
    $7.74 | U.S.
    $6.82 | 12,011        
|May                     | U.S.
    $8.66 | U.S.
    $7.58 | 12,495        
|June                    | U.S.
    $9.31 | U.S.
    $8.06 | 21,368        
|July                    | U.S.
    $8.39 | U.S.
    $7.80 | 9,038         
|August                  | U.S.
    $8.46 | U.S.
    $7.83 | 9,069         
|September               | U.S.
    $8.21 | U.S.
    $7.77 | 12,367        
|October                 | U.S.
    $8.53 | U.S.
    $7.85 | 13,968        
|November                | U.S.
    $8.89 | U.S.
    $8.12 | 16,581        
|December                | U.S.
    $8.84 | U.S.
    $8.37 | 9,666         

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 above 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:

- 50 -

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|                                |                                                    |                           | Number of Trust
    Units
|------------------------------- | -------------------------------------------------- | ------------------------- | -------------------------
|Name and
    Municipality of    |                                                    | Director of
    Provident | Beneficially Owned
    or
|Residence                       | Principal Occupation                               | Since                     | Controlled               
|G.D. Billing (2), (5)           | Executive Chairman, Superior Plus
    Inc., a      | 2001                      | 269,666                  
|Calgary, Alberta                | propane retailing,
    pulp chemicals and natural  |                           |                          
|                                | gas retailing company,
    since 1998. Prior       |                           |                          
|                                | thereto, President and
    Chief Executive Officer |                           |                          
|                                | of Norcen Energy Ltd.
    an oil and gas           |                           |                          
|                                | exploration and
    production company, from       |                           |                          
|                                | 1994 to 1998.                                      |                           |                          
|                                |                                                    |                           |                          
|Thomas W. Buchanan              | Chief Executive
    Officer of Provident since     | 2001                      | 1,258,761 (4)            
|Calgary, Alberta                | March 2001. Prior
    thereto, Executive Vice      |                           |                          
|                                | President Corporate
    Development and Chief      |                           |                          
|                                | Financial Officer of
    Founders Energy Ltd.      |                           |                          
|                                | from October 1999 to
    March 2001. Prior         |                           |                          
|                                | thereto, President and
    Chief Executive Officer |                           |                          
|                                | of Founders Energy
    Ltd. from 1996 to October   |                           |                          
|                                | 1999.                                              |                           |                          
|                                |                                                    |                           |                          
|Randall J. Findlay              | President of Provident
    since March 2001.       | 2001                      | 1,194,342 (4)            
|DeWinton, Alberta               | Prior thereto,
    Executive Vice President and    |                           |                          
|                                | Chief Operating
    Officer of Founders Energy     |                           |                          
|                                | Ltd. from December
    1999 to March 2001.         |                           |                          
|                                | Prior thereto, Senior
    Vice President of        |                           |                          
|                                | TransCanada Pipelines
    Ltd., a pipeline         |                           |                          
|                                | company, and President
    and Chief Executive     |                           |                          
|                                | Officer of TransCanada
    Gas Processing L.P., a  |                           |                          
|                                | gas processing
    partnership, from June 1998 to  |                           |                          
|                                | August 1999.                                       |                           |                          
|                                |                                                    |                           |                          
|Bruce R. Libin (1), (3)         | Chairman and Executive
    Chairman and Chief      | 2001                      | 42,192                   
|Calgary, Alberta                | Executive Officer of
    Destiny Resource          |                           |                          
|                                | Services Corp., a
    resource services company,   |                           |                          
|                                | since 1997 and
    December 2000, respectively.    |                           |                          
|                                | President of B.R.
    Libin Capital Corp., an      |                           |                          
|                                | investment, merchant
    banking and investment    |                           |                          
|                                | banking advisory
    services company since 1995   |                           |                          
|                                |                                                    |                           |                          
|M.H. (Mike) Shaikh
    (1), (5) | President of M.H.
    Shaikh Professional          | 2001                      | 29,320                   
|Calgary, Alberta                | Corporation (Chartered
    Accountants).           |                           |                          
|                                |                                                    |                           |                          
|Byron J. Seaman (3)             | Independent
    businessman and private investor.  | 2001                      | 38,735                   
|Calgary, Alberta                |                                                    |                           |                          
|                                |                                                    |                           |                          
|Jeffrey T. Smith (2), (3)       | Independent
    businessman and private investor.  | 2001                      | 4,900                    
|Calgary, Alberta                |                                                    |                           |                          
|                                |                                                    |                           |                          
|John B. Zaozirny (2)            | Counsel to the law
    firm of McCarthy            | 2001                      | 15,003                   
|Calgary, Alberta                | and Vice-Chairman of
    Canaccord                 |                           |                          
|                                | Tétrault LLP                                       |                           |                          
|                                | Capital Corporation.
    Director and strategic    |                           |                          
|                                | advisor to a number of
    public and private      |                           |                          
|                                | corporations, as well
    as a Governor of the     |                           |                          
|                                | Business Council of
    British Columbia.          |                           |                          
|                                |                                                    |                           |                          
|Norman R. Gish (1), (5)         | President, Gish
    Consulting Inc., energy        | 2003                      | 3,000                    
|                                | consultants, Director,
    Superior Plus Inc.,     |                           |                          
|                                | Noranda Inc. and
    Chairman and Director of      |                           |                          
|                                | Railpower Technologies
    Corp., Energreen        |                           |                          
|                                | Canada Corp. and
    Quadrise Canada Fuel          |                           |                          
|                                | Systems Inc. Prior
    thereto, Chairman,          |                           |                          
|                                | President and Chief
    Executive Officer of       |                           |                          
|                                | Alliance Pipeline Ltd.
    and Aux Sable Liquid    |                           |                          
|                                | Products Inc.                                      |                           |                          

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|                             |                                                   |                           | Number of Trust
    Units
|---------------------------- | ------------------------------------------------- | ------------------------- | -------------------------
|Name and
    Municipality of |                                                   | Director of
    Provident | Beneficially Owned
    or
|Residence                    | Principal Occupation                              | Since                     | Controlled               
|Dr. Robert Mitchell (3)      | Independent businessman since
    September       | 2004                      | Nil                      
|                             | 2003. Prior thereto,
    Executive Vice President |                           |                          
|                             | of Talisman Energy
    Inc. (and its predecessor  |                           |                          
|                             | BP Canada Inc.), a
    public oil and gas         |                           |                          
|                             | company, from 1984 to
    September 2003.         |                           |                          

Notes: (1) Member of the Audit Committee. 
(2) Member of the Governance, Human Resources and Compensation Committee. (3)
Member of the Reserves, Operations, Environment, Health and Safety Committee.

(4) Includes Trust Units issuable upon exchange of exchangeable shares of
Provident held by such director at an exchange ratio of 1.22632. 
(5) Mr. Billing also holds $250,000 principal amount of the Trust's 10.5%
convertible unsecured debentures (the "10.5% Debentures"). Mr. Shaikh also holds
$445,000 principal amount of the Trust's 10.5% debentures. Mr. Gish also holds
$20,000 principal amount of the Trust's 8.75% convertible unsecured subordinated
debentures.

The following is a brief description of the directors, senior officers and
key management and consulting personnel of Provident.

Grant D. Billing

Chairman of the Board

Mr. Billing has been Chairman of the Board since March 6,
2001 and serves on the Governance, Human Resources and Compensation Committee.
He was the senior executive officer of Superior Propane from October 1999 to
March 2001 and since 1998 has been the executive chairman of Superior Propane.
Previously, he was president and chief executive officer of Norcen Energy Ltd.,
an oil and gas exploration and production company, from 1994 to 1998.

Thomas W. Buchanan

Chief Executive Officer and Director

Mr. Buchanan obtained a B.Comm from the University of Calgary
in 1979 and a Chartered Accountant designation in 1981. He has over 19 years of
senior financial and management experience primarily in the oil and gas
industry. Mr. Buchanan has been Chief Executive Officer of Provident since March
2001 and prior thereto he was Executive Vice President and Chief Financial
Officer of Founders from October 1999 to March 2001. Prior thereto, Mr. Buchanan
was President and Chief Executive Officer of Founders since November 1993. Mr.
Buchanan has been a director of Provident or its predecessor since 1993.

Randall J. Findlay

President and Director

Mr. Findlay obtained a B.Sc in Chemical Engineering from the
University of British Columbia in 1973. He has more than 27 years of senior
management experience in all aspects of the oil and gas industry. Mr. Findlay
has been President of Provident since March 2001 and prior thereto he was
Executive Vice President, Chief Operating Officer and a director of Founders
from December 1999 to March 2001. He has been a director of TransAlta Power L.P.
since October, 2000. Prior thereto he was Senior Vice President of TransCanada
PipeLines Limited, President of TransCanada Midstream and President and Chief
Executive Officer of TransCanada Gas Processing L.P. from 1998 to 1999. From
1995 to 1997 he held senior executive positions at Novagas Canada Ltd. as
President and Executive Vice President of

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Novagas Canada Ltd. and Novagas Clearinghouse Ltd. Prior thereto, Mr. Findlay
held several senior executive positions at exploration and production companies
in the oil and gas industry.
Bruce R. Libin

Director
Mr. Libin, a member of Provident's Board of Directors since
May 2001, is a member of the Audit Committee as well as the Reserves,
Operations, Environmental, Health and Safety Committee. Libin was a director of
Maxx from December 2000 to May 2001. Mr. Libin is also the President of B.R.
Libin Capital Corp., an investment, merchant banking and investment banking
advisory services company. He joined Destiny Resource Services Corp., a resource
services company in 1997 currently holds the positions of Chairman, Chief
Executive Officer and Managing Director.
Byron J. Seaman

Director
Mr. Seaman, a member of Provident's Board of Directors since
March 2001, serves on the Reserves, Operations, Environment, Health and Safety
Committee. He is a recipient of the Governor General's Medal in 1993 and has
over 50 years of experience in various positions in the oil, gas and resources
industries on a world-wide basis. He served as chief executive officer of Bow
Valley Resource Services Ltd. from 1976 to 1987, and then as Chairman of the
Board until 1990. He is also on the Boards of Rider Resources Ltd., Zargon Oil &
Gas Ltd, and is a director and part owner of the Calgary Flames Hockey Club.
M.H. (Mike) Shaikh

Director
Mr. Shaikh, chairman of the Audit Committee, has been a
Provident board member since March 2001. He is president of M.H. Shaikh
Professional Corporation (Chartered Accountants). Mr. Shaikh is currently, or
has been a director of Hawk Oil Ltd., Winstar Resources Ltd., IMS Petroleum
Ltd., and Spearhead Resources Ltd.
John B. Zaozirny, Q.C.

Director
Mr. Zaozirny, a member of Provident's Board of Directors
since March 2001, is also the chairman of the Governance, Human Resources and
Compensation Committee. He is counsel to the law firm of McCarthy Tetrault and
vice-chairman of Canaccord Capital Corporation. Mr. Zaozirny is also a director
and a strategic advisor to a number of public and private corporations, as well
as a Governor of the Business Council of British Columbia. He served as
Alberta's Minister of Energy and Natural Resources from 1982 to 1986, having
first been elected as a member of the Alberta Legislature in 1979.
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Jeffrey Smith

Director
Mr. Smith has been a member of Provident's Board of Directors
since May 2001. He serves on the Governance, Human Resources and Compensation
committee as well as being chairman of the Reserves, Operations, Environment,
Health and Safety Committee. He was a director of Maxx from December 2000 to May
2001 and prior thereto was the chief operating officer of Northstar Energy Ltd.
Norman R. Gish

Director
Mr. Gish, a member of Provident's Board of Directors since
October 2003, serves on the Audit committee. Mr. Gish has served as chairman,
president, CEO and director of Alliance Pipeline and Aux Sable Liquids Products
Inc, as well as senior leadership roles at North Canadian Oils and Turbo
Resources. In 1993, he became the managing director of Fracmaster China and was
located in Beijing for three years. Prior to the energy industry, he was
chairman of the British Columbia Energy Commission; and vice president, general
counsel and secretary of British Columbia Forest Products in Vancouver.
Currently, he serves as director on the boards of Superior Plus Inc., Noranda
Inc., Railpower Technologies Corp, Energreen Canada Corp., and Quadrise Canada
Fuel Systems.
Dr. Robert Mitchell

Director
Dr. Mitchell has been a member of Provident's Board of
Directors since January 2004. He serves on the Reserves, Operations,
Environment, Health & Safety Committee of Provident. Dr. Mitchell has had a long
and distinguished career in North America and abroad in the oil and gas
industry. In September 2003, he retired from Talisman Energy as executive vice
president of North American operations. As a Chartered Professional Engineer,
Dr. Mitchell is a member of the Advisory Committee to the Alberta Energy and
Utilities Board and the Society of Petroleum Engineers. He is a director of the
Petroleum Technology Research Centre in Saskatchewan, the Canadian Gas Potential
Committee, and a former director of the Canadian Association of Petroleum
Producers.
Mark N. Walker

Vice President, Chief Financial Officer and Corporate Secretary
Mark Walker is Vice President of Finance, Chief Financial
Officer and Corporate Secretary of Provident. A member of Provident's senior
leadership team, Mr. Walker is responsible for all finance, financial reporting,
treasury, and compliance activities. Prior to the appointment to his current
position, Mr. Walker served as controller and CFO from 1997 to 2002. Mr. Walker
joined Provident's predecessor Founders in 1996 as controller.
Mr. Walker has over 19 years of experience in petroleum
finance and accounting. Prior to joining Founders, Mr. Walker was team lead of
financial reporting for Sceptre Resources, first joining the company in 1990.
From 1988 to 1990, Mr. Walker was a revenue accountant with Dome Petroleum.
Before Dome, Mr. Walker was an accountant with Hudson & Company from 1985 to
1988.
- 54 -

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Mr. Walker received his bachelor of commerce in Accounting from the
University of Calgary and later received his Certified Management Accountant
designation.
Cameron Vouri

Vice President, Production Operations and Chief Operating Officer
Mr. Vouri obtained a Bachelor of Science (Petroleum
Engineering) degree from New Mexico Institute of Mining and Technology in 1988.
He as been 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.
David Fricker

Vice President, Corporate Development

From 2000 to 2002, Mr. Fricker was based in Saudi Arabia and
worked for Saudi Aramco Oil as a petroleum-engineering specialist. He was a
senior business advisor for Kuwait Oil Company in Kuwait from 1998 to 2000.
Prior to working overseas, Mr. Fricker was manager of business development with
Canada-based Ranger Oil from 1996 to 1998. Mr. Fricker joined Ranger in 1993 as
a senior production engineer and was appointed engineering manager in 1994.
Prior to 1994, Mr. Fricker held senior petroleum engineering positions with Bow
Valley Resources and Gulf Canada.
Mr. Fricker holds a Bachelor of Science in chemical engineering from the
University of Saskatchewan.
Gary Kline

Vice President, Commercial Development
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
Gary began his energy industry career as a regulatory analyst at TransCanada
Pipelines in 1982.
Mr. Andrew Gruszecki

Vice President, NGL Services
Mr. Gruszecki received his honors 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,
Andy 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, Andy oversaw commercial issues related
to the planning, construction and implementation of the NGL business which
included the construction of
- 55 -

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the Redwater fractionation facilities. Andy began his career in the energy
business in 1981 and held positions of increasing responsibility before joining
Novagas in 1997.
Committees of the Board

The Board presently has three standing committees, being an
Audit Committee, Governance, Human Resources and Compensation Committee and a
Reserves, Operations, Environment, Health and Safety Committee. All of the
members of each committee are unrelated directors.
Audit Committee
The Audit Committee consists of Mr. M.H. (Mike) Shaikh
(Chairman), Mr. Bruce R. Libin and Mr. Norman R. Gish. The Audit Committee
reviews the Trust's interim unaudited consolidated financial statements and
annual audited consolidated financial statements and certain corporate
disclosure documents including the annual information form, management's
discussion and analysis and annual and interim earnings press releases before
they are approved by the board of directors. The Committee 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 it is directly responsible for
overseeing the work of the external auditor with respect to the preparing or
issuing of 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 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. 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.
Governance, Human Resources and Compensation Committee
The Governance, Human Resources and Compensation Committee
consists of Mr. John B. Zaozirny (Chairman), Mr. Grant D. Billing and Mr.
Jeffrey T. Smith. 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 issues and in compiling the results of a directors' questionnaire
dealing with the effectiveness of the board of directors, its members and its
committees.
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. 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 Option Plan and makes
recommendations to the board of directors respecting grants of options
thereunder.
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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 and Mr. Byron J. Seaman. 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.
The Committee is responsible for ensuring that management has
in place effective programs relating to environment, health and safety matters,
including the identification of risks and the compliance with legal
requirements, and ensuring that management administers Provident's policies and
procedures on these matters.
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.
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.INFORMATION CONCERNING THE OIL AND GAS INDUSTRY
Canadian Government RegulationThe 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.
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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.
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.
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Alberta

In Alberta, a producer of oil or natural gas is entitled to a
credit against the royalties payable to the Crown by virtue of the ARTC program.
The ARTC rate is based on a price-sensitive formula and varies between 75
percent for prices at or below the royalty tax credit reference price of $100
per m3 decreasing to 25 percent for prices above the royalty tax
credit reference price of $210 per m3. The ARTC rate will be applied
to a maximum annual amount of $2,000,000 of Alberta Crown royalties payable for
each producer or associated group of producers. Crown royalties on production
from producing properties acquired from corporations claiming maximum
entitlements to ARTC will generally not be eligible for ARTC. The rate is
established quarterly based on the average par price, as determined by the
Alberta Department of Energy.
On October 13, 1992, the Alberta government announced major
changes to its royalty structure and permanent incentives for exploring and
developing oil and gas reserves. The significant changes announced which remain
in force include the following: (i) the first wells drilled in new oil pools
discovered on or after October 1, 1992 will have a permanent one year oil
royalty holiday, subject to a $1,000,000 cap and a reduced royalty rate
thereafter; (ii) reduction of royalties on pre-October 1, 1992 production of oil
and gas; (iii) incentives by way of royalty holidays and reduced royalties on
reactivated, low productivity and horizontal re-entry of vertical oil wells;
(iv) introduction of separate par pricing for light, medium and heavy oil; and
(v) modification of the royalty formula structure to provide for sensitivity to
price fluctuations.
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. Environmental legislation in Alberta has been consolidated into the
Environmental Protection and Enhancement Act (Alberta), which took effect
on September 1, 1993. TheEnvironmental Protection and Enhancement Act
(Alberta) imposes stricter environmental standards, requires more stringent
compliance and reporting and significantly increases penalties for
non-compliance.
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 Midstream NGL Assets, 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

- 59 -

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royalties. Provident's income will be received from the cash
flow generated from the Midstream NGL Assets and from the production of oil and
natural gas from Provident's existing Canadian 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 Canadian 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 DevelopmentExploitation and development risks are due to the uncertain
results of searching for and producing oil and natural gas using imperfect
scientific methods. These risks are mitigated by using experienced staff,
focusing exploitation efforts in areas in which Provident has existing knowledge
and expertise or access to such expertise, using up-to-date technology to
enhance methods and controlling costs to maximize returns. Advanced oil and
natural gas related technologies such as three dimensional seismography,
reservoir simulation studies and horizontal drilling have been used by Provident
and will be used by Provident to improve its ability to find, develop and
produce oil and natural gas.
Operations
Provident's operations will be subject to all of the risks
normally incident to the operation and development of oil and natural gas
properties and the drilling of oil and natural gas wells, including encountering
unexpected formations or pressures, blowouts, craterings and fires, all of which
could result in personal injuries, loss of life and damage to property of
Provident and others. Provident will have both safety and environmental policies
in place to protect its operators and employees, as well as to meet the
regulatory requirements in those areas where it operates. In addition, Provident
will have liability insurance policies in place, in such amounts as it considers
adequate, however, it will not be fully insured against all of these risks, nor
are all such risks insurable.
Continuing production from a property, and to some extent the
marketing of production therefrom, are largely dependent upon the ability of the
operator of the property. To the extent the operator fails to perform these
functions properly, revenue may be reduced. Payments from production generally
flow through the operator and there is a risk of delay and additional expense in
receiving such revenues if the operator becomes insolvent. Although satisfactory
title reviews are generally conducted in accordance with industry standards,
such reviews do not guarantee or certify that a defect in the chain of title may
not arise to defeat the claim of Provident to certain of its oil and gas
properties. A reduction of the income from the Provident Royalties could result
in such circumstances.
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.
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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.
Debt Service
Provident currently has a term credit facility of $335
million. In February 2004, Provident executed a credit agreement consent and
amendment that restricted the borrowing base under this Facility to $310
million. Variations in interest rates and scheduled principal repayments could
result in significant changes in the amount required to be applied to debt
service before payment of any amounts to the Trust. Although it is believed that
the bank line of credit is sufficient, there can be no assurance that the amount
will be adequate for the financial obligations of Provident or that additional
funds can be obtained.
The lender has 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
lender may foreclose on or sell Provident's oil and gas properties free from or
together with the Provident Royalties.
Reserves
Although McDaniel 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 Trust
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.
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.
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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. Distributions of 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.Midstream NGL Asset Risk Factors
Facilities ThroughputThe volumes of natural gas processed at the Midstream NGL
Assets and of NGLs and other products transported in the pipelines depend on
production of natural gas in the areas serviced by the Midstream NGL Assets 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 Midstream NGL Assets 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
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which encourages producers to explore for and develop additional reserves or
produce existing marginal reserves.
The rate and timing of production from proven natural gas
reserves tied into the gas plants is at the discretion of the producers and is
subject to regulatory constraints. The producers have no obligation to produce
natural gas from these lands.
The Midstream NGL Assets are connected to various third party
trunkline systems. Operational disruptions or apportionment on those third party
systems may prevent the full utilization of the Midstream NGL Assets.
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.
Bank Financing
Provident has secured a $120 million bank credit facility
which was used to finance the portion of the purchase price of the Redwater
Acquisition not covered by the offering of Trust Units and 8.75% Debentures.
Variations in interest rates and scheduled principal repayments could result in
significant changes in the amount required to be applied to debt service before
payment of any amounts to the Trust. Although it is believed that this credit
facility is sufficient, there can be no assurance that the amount will be
adequate for the financial obligations of Provident or that additional funds can
be obtained.
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.
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 the Midstream NGL Assets 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 the Midstream NGL Assets 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.
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Operating and Capital Costs
Operating and capital costs of the Midstream NGL Assets 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
The Midstream NGL Assets are subject to competition from
other gas processing plants which are either in the general vicinity of the gas
plants or have gathering systems that are or could potentially extend into areas
served by the gas plants. The pipelines and storage, terminal and processing
facilities are also subject to competition from other pipelines and storage,
terminal and processing facilities in the areas they serve, and the gas products
marketing business is subject to competition from other marketing firms.
Producers in Alberta compete with producers in other regions
to supply natural gas and gas products to customers in North America and the
natural gas and gas products industry also competes with other industries to
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 the Midstream NGL
Assets, 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 the Midstream NGL Assets at the end of their economic
life, which abandonment costs may be substantial. It
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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.General Risk Factors
Risks Associated With the Level of Foreign OwnershipGenerally, 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% 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% of the trust's
property has at any time consisted of "taxable Canadian property". Prior to the
Budget, Canadian resource property, including a resource royalty, was not
"taxable Canadian property" for this purpose, and therefore a number of resource
royalty trusts, including the Trust, were not required to restrict nonresident
ownership of their units. Under the Budget proposals, the definition of "taxable
Canadian property" for this purpose will be amended so as to include Canadian
resource property, and therefore resource royalty trusts, including the Trust,
will be required to restrict non-resident ownership of their units prior to
January 1, 2007.
The retention of "mutual fund trust" status under the Tax Act
is important for both resident and nonresident holders of Trust Units and not
just for holders of Trust units held within Canadian tax exempt plans. The loss
of such status could be expected to have a significant adverse effect on the
market price of the Trust Units. The importance of mutual fund status and the
consequences of losing such status are set forth below:
(a) By virtue of its status as a mutual fund trust, the
  Trust has been accepted for registration effective March 6, 2001 as a
  "registered investment" for registered retirement savings plans ("RRSPs"),
  registered retirement income funds ("RRIFs"), and deferred profit sharing
  plans ("DPSPs") (collectively, "Exempt Plans"). As such, Trust Units are
  qualified investments for Exempt Plans as well as registered education savings
  plans ("RESPs") and if the Trust's status as a "registered investment" is
  revoked in any year by virtue of ceasing to be a "mutual fund trust" the Trust
  Units would remain as qualified investments for Exempt Plans and RESPs until
  the end of the year following such year;
  (b) Where at the end of any month an Exempt Plan or a RESP
  holds Trust Units that are not qualified investments, the Exempt Plan or RESP
  must, in respect of that month, pay a tax under Part XI.1 of the Tax Act equal
  to 1 percent of the fair market value of the Trust Units at the time such
  Trust Units were acquired by the Exempt Plan or RESP. An RRSP or RRIF holding
  Trust Units that are not qualified investments would become taxable on income
  attributable to the Trust Units while they are not qualified investments
  (including the entire amount of any capital gain arising on a disposition of
  the non-qualified investment). RESPs which hold Trust Units that are not
  qualified investments may have their registration revoked by the Canada
  Customs and Revenue Agency;
  (c) Trust Units would become foreign property for
  registered pension plans upon the Trust ceasing to be a mutual fund trust. If
  the Trust's "registered investment" status is revoked by virtue of it ceasing
  to be a mutual fund trust, then the Trust Units would also become foreign
  property for Exempt Plans;
  (d) The loss of mutual fund trust status would also render the Trust liable
  for the payment of a tax under Part XII.2 of the Tax Act in respect of certain
  designated income. The payment of
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Part XII.2 tax by the Trust could have adverse consequences
  to Unitholders who are not residents of Canada and to certain Unitholders
  which are tax exempt entities since the amount of cash available for cash
  distributions would be reduced by the amount of such tax;
  (e) The loss of mutual fund trust status would result in the Trust ceasing
  to be eligible for the capital gains refund mechanism available under the Tax
  Act; and
  (f) Upon the loss of mutual fund trust status, the Trust
  Units held by Unitholders that are not residents of Canada would become
  taxable Canadian property. Such Unitholders would be subject to Canadian
  income tax on any gains realized on a disposition of Trust Units, and to
  reporting requirements in respect thereof.
  As a result of the proposed amendments to the Tax Act, for the purpose of
  qualifying as a "mutual fund trust" under the Tax Act, Provident may:
  (a) 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 that the Trust Units to be
  issued or transferred to such person will (when issued or transferred) not be
  beneficially owned by a non-resident;
  (b) 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). 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;
  (c) delist the Trust Units from any non-Canadian stock exchange; and
  (d) 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
  nonresident Unitholders to ensure that the Trust is not maintained primarily
  for the benefit of nonresidents.
  Changes in Legislation

There can be no assurance that the treatment of mutual fund
trusts will not be changed in a manner, which adversely affects Trust
Unitholders. If the Trust ceases to qualify as a "mutual fund trust" under the
Tax Act, the Trust Units will cease to be qualified investments for registered
retirement savings plans, deferred profit sharing plans and registered
retirement income funds.
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Investment Eligibility
The Trust will endeavour to ensure that the Trust Units
continue to be qualified investments for registered retirement savings plans,
deferred profit sharing plans and registered retirement income funds. The Tax
Act imposes penalties for the acquisition or holding of non-qualified or
ineligible investments and there is no assurance that the conditions prescribed
for such qualified or eligible investments will be adhered to at any particular
time.
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 the Canada 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.

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.

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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 NGL marketing business, to achieve positive margins. The
continued success of Provident will be dependent on its ability to retain or
recruit such personnel.
INTERESTS OF MANAGEMENT AND OTHERS IN MATERIAL TRANSACTIONS

No director or executive officer of Provident, no person or
company that is the direct or indirect beneficial owner of, or who exercises
control or direction over more than 10% 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 will 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 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 principals of Seaton Jordan &
Associates Ltd., independent land appraisers, as a group, did not beneficially
own, directly or indirectly, any of the Trust Units. As of the date hereof, the
principals of McDaniel & Associates Consultants Ltd., independent oil and gas
reservoir engineers, as a group, beneficially own, directly or indirectly, less
than 1 percent of the Trust Units.
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DOCUMENTS INCORPORATED BY REFERENCE
Any statement contained in a document incorporated or deemed
to be incorporated by reference herein shall be deemed to be modified or
superseded for the purposes of this Annual Information Form to the extent that a
statement contained herein, or any other subsequently filed document which also
is or is deemed to be incorporated by reference herein, modifies or supersedes
that statement. The modifying or superseding statement need not state that it
has modified or superseded a prior statement or include any other information
set forth in the document that is modified or superseded. The making of a
modifying or superseding statement shall not be deemed an admission for any
purposes that the modified or superseded statement, when made, constituted a
misrepresentation, an untrue statement of a material fact or an omission to
state a material fact that is required to be stated or that is necessary to make
a statement not misleading in light of the circumstances in which it was made.
Any statement so modified or superseded shall not be deemed, except as so
modified or superseded, to constitute a part of this Annual Information Form.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., 700, 112 - 4th Street
S.W., Calgary, Alberta T2P 0H3, telephone: (403) 296-2233. Documents
incorporated by reference in this Annual Information Form are also available on
SEDAR at www.sedar.com.ADDITIONAL INFORMATION
Principal Holders of Trust UnitsAs at the date hereof, to the knowledge of Provident, no
person or company owned of record or beneficially, directly or indirectly, more
than 10% of the issued and outstanding Trust Units. As at April 20, 2004,
the directors and senior officers of Provident, as a group, beneficially owned,
directly or indirectly, 1,461,520 Trust Units or approximately 1.6%of
the issued and outstanding Trust Units and 1,040,576 exchangeable shares of
Provident representing 100% of the issued and outstanding exchangeable shares of
Provident. As of April 20, 2004, each such exchangeable share of Provident held
by such director or senior officer is exchangeable into Trust Units at an
exchange ratio of 1.23909. The directors and senior officers of Provident do not
beneficially own, directly or indirectly, or exercise control or direction over
any of the exchangeable shares of PAI.
Requests for Information

Provident will provide to any person, upon request to the Corporate Secretary
of Provident:
1.
when the securities of the
Trust are in the course of a distribution pursuant to a short form prospectus or
a preliminary short form prospectus has been filed in respect of a proposed
distribution of its securities:

> (a)one copy of the
>   Annual Information Form of the Trust, together with one copy of any document,
>   or the pertinent pages of any document, incorporated by reference in the
>   Annual Information Form;

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(b)one copy of the
  consolidated financial statements of the Trust for the completed financial
  year ended December 31, 2003, together with the accompanying report of the
  auditors thereon, as well as one copy of any interim consolidated financial
  statements of the Trust subsequent to December 31, 2003;

(c)
  one copy of the
  Management Proxy Statement and Information Circular of the Trust dated April
  9, 2004; and

(d)one copy of any
  other documents that are incorporated by reference into the preliminary short
  form prospectus or the short form prospectus that are not required under
  paragraphs a, b, or c above; or

2.
at any time, one copy of
any of the document referred to in paragraphs 1(a), (b), and (c) above, provided
Provident may require the payment of a reasonable charge if the request is made
by a person who is not a security holder of the Trust.

Additional information related to the remuneration of the
directors and officers of Provident, the remuneration of the Manager for the
year ended December 31, 2003, the indebtedness of the directors and officers of
Provident, the principal holders of Trust Units and options to purchase Trust
Units, where applicable, is contained in the Management Proxy Statement and
Information Circular of the Trust dated April 9, 2004, which relates to the
Annual and Special Meeting of the Unitholders to be held on May 10, 2004.
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, 2003.

Additional copies of this Annual Information Form may be obtained from
Provident. Please contact:

> Jennifer Pierce 
>   Investor Relations 
>   Provident Energy Ltd. 
>   700, 112 - 4th Street S.W. 
>   Calgary, Alberta T2P 0H3
>   Telephone: (403) 296-2233Fax: (403) 261-6696

Additional information relating to the Trust may be found on SEDAR at
www.sedar.com.

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SCHEDULE A
FINANCIAL STATEMENTS OF THE REDWATER NATURAL GAS 
LIQUIDS PROCESSING SYSTEM OF WILLIAMS ENERGY (CANADA), INC.AUDITORS' REPORT

To the Board of Directors of Williams Energy (Canada), Inc.

We have audited the balance sheet of the Redwater Natural Gas
Liquids Processing System, a segment of Williams Energy (Canada), Inc. as
at December 31, 2002 and the statements of operations and cash flows for the
year then ended. These financial statements are the responsibility of the
segment's management. Our responsibility is to express an opinion on these
financial statements based on our audit.

We conducted our audit in accordance with Canadian generally
accepted auditing standards. Those standards require that we plan and perform an
audit to obtain reasonable assurance whether the financial statements are free
of material misstatement. An audit includes examining, on a test basis, evidence
supporting the amounts and disclosures in the financial statements. An audit
also includes assessing the accounting principles used and significant estimates
made by management, as well as evaluating the overall financial statement
presentation.

In our opinion, these financial statements present fairly, in
all material respects, the financial position of the Redwater Natural Gas
Liquids Processing System as at December 31, 2002 and the results of its
operations and its cash flows for the year then ended in accordance with
Canadian generally accepted accounting principles.

As discussed in note 1, the Redwater Natural Gas Liquids
Processing System is a component of Williams Energy (Canada), Inc. and has no
separate legal status. Transactions with other segments and affiliates of
Williams Energy (Canada), Inc. are described in note 6.

|Calgary, Canada   | (Signed) ERNST & YOUNG LLP
|----------------- | --------------------------
|July
    31, 2003 | Chartered Accountants     

A-1

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The Redwater Natural Gas Liquids Processing System of 
Williams Energy (Canada), Inc.BALANCE SHEETS
(thousands of Canadian dollars) 
(see basis of presentation - note 1)

As at

|                                                           | June 30, 2003 | December 31, 2002
|---------------------------------------------------------- | ------------- | -----------------
|                                                           | $             | $                
|                                                           | (unaudited)   |                  
|                                                           |               |                  
|ASSETS                                                     |               |                  
|Current                                                    |               |                  
|Accounts receivable                                        | 51,825        | 61,077           
|Inventories [note 2]                                       | 27,023        | 22,446           
|Prepaid
    expenses [note 3]                              | 21,088        | 20,305           
|Due from affiliates [note 6]                               | 7,041         | 11,625           
|                                                           | 106,977       | 115,453          
|                                                           |               |                  
|Property, plant and
    equipment [note 4]                 | 170,510       | 169,984          
|                                                           | 277,487       | 285,437          
|                                                           |               |                  
|                                                           |               |                  
|LIABILITIES AND EQUITY                                     |               |                  
|Current                                                    |               |                  
|Accounts payable and accrued liabilities                   | 46,349        | 64,074           
|Due to an affiliate [note 6]                               | 3,345         | 9,153            
|                                                           | 49,694        | 73,227           
|                                                           |               |                  
|Future income tax
    liability [note 5]                   | 33,777        | 35,233           
|                                                           | 83,471        | 108,460          
|                                                           |               |                  
|Contingencies and commitments [notes 1, 8 and 10]          |               |                  
|                                                           |               |                  
|Williams Energy
    (Canada), Inc. net investment [note 7] | 194,016       | 176,977          
|                                                           | 277,487       | 285,437          

See accompanying notes.

On behalf of the Board:

> (Signed) Alan
>             S. Armstrong
>             (Signed)
>             Phillip D. WrightDirector
>             Director

A-2

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The Redwater Natural Gas Liquids Processing
System of 
Williams Energy (Canada), Inc.STATEMENTS OF OPERATIONS
(thousands of Canadian dollars) 
(see basis of presentation - note 1)

|                                      | Six months ended | Year ended  
|------------------------------------- | ---------------- | ------------
|                                      | June 30          | December 31,
|                                      | 2003             | 2002        
|                                      | $                | $           
|                                      | (unaudited)      | (unaudited) 
|                                      |                  |             
|Revenues                              |                  |             
|Natural
    gas liquid sales [note 6] | 341,270          | 219,402     
|Processing and other
    fees         | 9,618            | 6,652       
|                                      | 350,888          | 226,054     
|                                      |                  |             
|Expenses                              |                  |             
|Production [note 6]                   | 318,734          | 194,610     
|Operating and maintenance             | 17,169           | 16,466      
|General
    and administrative        | 4,234            | 3,530       
|Bad
    debt expense                  | 8,418            | -           
|Depreciation                          | 3,079            | 2,876       
|                                      | 351,634          | 217,482     
|                                      |                  |             
|Income before interest and taxes      | (746)            | 8,572       
|Interest expense                      | (3,203)          | (3,207)     
|Interest capitalized                  | 59               | 80          
|Other expense                         | (194)            | (83)        
|Income (loss) before
    income taxes | (4,084)          | 5,362       
|                                      |                  |             
|Income tax expense (recovery)[note 5] |                  |             
|Current                               | (117)            | 235         
|Future                                | (1,433)          | 2,103       
|                                      | (1,550)          | 2,338       
|                                      |                  |             
|Net income (loss)
    for the period  | (2,534)          | 3,024       
|                                      |                  |             

See accompanying notes.

A-3

---

The Redwater Natural Gas Liquids Processing
System of 
Williams Energy (Canada), Inc.STATEMENTS OF CASH FLOWS
(thousands of Canadian dollars) 
(see basis of presentation - note 1)

|                                                          |                  |              |         
|--------------------------------------------------------- | ---------------- | ------------ | --------
|                                                          | Six months ended | Year ended  
|                                                          | June 30,         | December 31,
|                                                          | 2003             | 2002         | 2002    
|                                                          | $                | $            | $       
|                                                          | (unaudited)      | (unaudited)  |         
|                                                          |                  |              |         
|Operating activities                                      |                  |              |         
|Net
    income (loss) for the period                      | (2,534)          | 3,024        | 13,554  
|Items
    not affecting cash                              |                  |              |         
|Depreciation                                              | 3,079            | 2,874        | 5,899   
|Future income taxes                                       | (1,433)          | 2,103        | 6,260   
|                                                          | (888)            | 8,001        | 25,713  
|                                                          |                  |              |         
|                                                          |                  |              |         
|Changes in non-cash
    working capital balances [note 9] | (15,057)         | 21,336       | 20,917  
|                                                          | (15,945)         | 29,337       | 46,630  
|                                                          |                  |              |         
|Investing activities                                      |                  |              |         
|Capital asset additions                                   | (3,606)          | (10,437)     | (11,533)
|                                                          |                  |              |         
|Financing activities                                      |                  |              |         
|Cash
    equity funding from (distributions to) Williams  |                  |              |         
|Energy (Canada), Inc.                                     | 19,551           | (18,900)     | (35,097)
|                                                          |                  |              |         
|Net change in cash                                        | -                | -            | -       
|                                                          |                  |              |         

See accompanying notes.

A-4

---

The Redwater Natural Gas Liquids Processing
System of 
Williams Energy (Canada), Inc.NOTES TO FINANCIAL STATEMENTS(Amounts are
stated in thousands of Canadian dollars)

June 30, 2003 and December 31, 2002

1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

Basis of presentation

These financial statements have been prepared in connection
with the planned sale of the Redwater Natural Gas Liquids Processing System ("Redwater")
of Williams Energy (Canada), Inc. ("WECI" or the "Company"). These financial
statements present the historic financial position, results of operations and
cash flows of WECI's Redwater assets including Williams Energy (Canada)
Pipelines Inc, a wholly owned subsidiary of WECI, on a carve-out basis from WECI
as if they had operated as a stand-alone entity subject to WECI's control. The
Redwater assets are comprised of the paraffin extraction and fractionation
assets of the Redwater facility, a liquids gathering system and the Younger
plant. Redwater's financial statements have been prepared by management in
accordance with Canadian generally accepted accounting principles.

The financial statements include WECI's interests in the
assets, liabilities, revenues and expenses directly attributable to Redwater and
management's estimates of general and administrative expenses and interest
expenses directly related to these operations. General and administrative
expenses have been allocated based on the percentage of commercial activity
related to Redwater relative to the overall commercial activities within WECI
while interest expenses have been allocated based on the specific usage of the
proceeds from the related debt. These estimates are considered by management to
be the best available approximation of the expenses that Redwater would have
incurred had it operated on a stand-alone basis over the periods presented.
Income taxes have been calculated based upon the combined federal and provincial
marginal income tax rate in Alberta. Redwater has not issued any debt or equity.
All excess cash flows are assumed to be distributed to WECI and all cash flow
deficiencies are assumed to be funded by WECI.

The accompanying financial statements have been prepared from
the books and records of the Company. As a result of the basis of presentation
described above, these financial statements may not necessarily be indicative of
the results that would have been attained if Redwater had operated as a
stand-alone entity for the periods presented.

The assets of Redwater are available for the satisfaction of
the debts, contingent liabilities and commitments of Williams Energy (Canada),
Inc. and not just those liabilities presented in the accompanying balance sheet.

Use of estimates

The preparation of financial statements in conformity with
Canadian generally accepted accounting principles requires management to make
estimates and assumptions that affect the amounts reported in these financial
statements and accompanying notes. Actual results could differ from those
estimates.

A-5

---

The Redwater Natural Gas Liquids Processing
System of 
Williams Energy (Canada), Inc.NOTES TO FINANCIAL STATEMENTS
(Amounts are stated in thousands of Canadian dollars)

June 30, 2003 and December 31, 2002

Inventory valuation

Inventories for natural gas liquids are stated at the lower
of average cost or quoted market price. Inventories for parts and supplies are
stated at the lower of average cost or net realizable value. Because of the
inherent limitations in metering and the physical properties of storage caverns,
the determination of precise volumes of natural gas liquids held in inventory at
such locations is subject to estimation. Actual amounts, which can only be
determined by draining caverns, may differ from these estimates.

Property, plant and equipment

Property, plant and equipment are recorded at cost.
Depreciation of plant and equipment is provided on the straight-line method over
estimated useful lives which range from 15 to 30 years. Gains or losses from the
ordinary sale or retirement of property are recorded in net income. Repairs and
maintenance costs on plant and equipment are charged to expense as incurred.

Inventories used to fill in cavern bottoms are presented as part of property,
plant and equipment and stated at historical cost. These inventories are not
depreciated.

Future site restoration and abandonment costs

Future site restoration and abandonment costs in excess of
expected salvage values are charged to income over the expected useful life of
the gas plant or gathering line. Decommissioning costs, potential environmental
clean-up costs to restore processing plant or gathering line sites to original
condition are estimated based on costs and regulations in effect at yearend.
These costs and salvage values are evaluated annually.

Revenue recognition

Revenues for sales of natural gas liquids are recognized in the period of
delivery and revenues from processing and other fees are recorded when services
have been performed.

Interest capitalization

Interest is capitalized on major projects during construction using the
parent company's weighted average interest rate.

Income taxes

Income taxes for Redwater are recorded using the liability
method of accounting. Under the liability method, the Redwater records future
income taxes for the effect of any difference between the accounting and income
tax basis of an asset or liability using substantively enacted income tax rates
and laws that will be in effect when the differences are expected to be
reversed. Income tax expense for the period is the tax payable for the period
and any change during the period in future tax assets and liabilities.

A-6

---

The Redwater Natural Gas Liquids Processing
System of 
Williams Energy (Canada), Inc.NOTES TO FINANCIAL STATEMENTS
(Amounts are stated in thousands of Canadian dollars)

June 30, 2003 and December 31, 2002

Foreign currency translation

Transactions denominated in foreign currencies are translated
at the exchange rate on the transaction date. Foreign currency denominated
monetary assets and liabilities are translated at exchange rates in effect on
the balance sheet date. Gains and losses arising from this translation process
are included in income.

Derivative instruments

Derivative instruments are used by the Company to hedge
Redwater's exposure to market risks relating to commodity prices. The Company's
policy is not to utilize derivative financial instruments for trading or
speculative purposes.

The Company formally documents all relationships between
hedging instruments and hedged items, as well as its risk management objective
and strategy for undertaking various hedge transactions. This process includes
linking all derivatives to specific assets and liabilities on the balance sheet
or to specific firm commitments or forecasted transactions. The Company also
formally assesses, both at the hedge's inception and on an ongoing basis,
whether the derivatives that are used in hedging transactions are highly
effective in offsetting changes in fair values or cash flows of hedged items.

Redwater applies settlement accounting to derivative
instruments. Under this method, gains and losses on derivative instruments used
as hedges are recognized in the period that the hedged instrument is settled by
netting the gain or loss against the income or expense item that is hedged.

Seasonality

The Company's extraction and fractionation business is highly
seasonal relative to gas deliveries occurring during the winter heating season.
Majority of gas deliveries occur during the winter resulting typically in
stronger first and fourth quarter results.

A-7

---

The Redwater Natural Gas Liquids Processing
System of Williams Energy (Canada), Inc.NOTES TO FINANCIAL STATEMENTS
(Amounts are stated in thousands of Canadian dollars)

June 30, 2003 and December 31, 2002

2.

|                        | June 30, 2003 | December 31, 2002
|----------------------- | ------------- | -----------------
|                        | $             | $                
|                        | (unaudited)   |                  
|                        |               |                  
|Natural
    gas liquids | 26,601        | 22,058           
|Parts and supplies      | 422           | 388              
|                        | 27,023        | 22,446           

3.

Cash provided as financial assurances by WECI on behalf of
Redwater to certain customers under current and long-term contracts amounting to
$21,088 as at June 30, 2003 (December 31, 2002 - $16,525) have been classified
as prepaid expenses.

4.

|                                                         | June 30, 2003 | December 31, 2002
|-------------------------------------------------------- | ------------- | -----------------
|                                                         | $             | $                
|                                                         | (unaudited)   |                  
|                                                         |               |                  
|Land                                                     | 4,642         | 4,642            
|Assets
    under construction                            | 5,220         | 2,115            
|Operating inventory                                      | 2,938         | 2,938            
|Plant and equipment                                      | 173,701       | 173,200          
|                                                         | 186,501       | 182,895          
|Less accumulated
    amortization on plant and equipment | (15,991)      | (12,911)         
|Net book value                                           | 170,510       | 169,984          

A-8

---

The Redwater Natural Gas Liquids Processing
System of 
Williams Energy (Canada), Inc.NOTES TO FINANCIAL STATEMENTS
(Amounts are stated in thousands of Canadian dollars)

June 30, 2003 and December 31, 2002

5.

|                                                   | Six months ended | Year ended  
|-------------------------------------------------- | ---------------- | ------------
|                                                   | June 30,         | December 31,
|                                                   | 2003             | 2002        
|                                                   | $                | $           
|                                                   | (unaudited)      | (unaudited) 
|                                                   |                  |             
|Statutory Canadian federal and provincial          |                  |             
|income
    tax rate                                | 41.87%           | 42.37%      
|Rate
    Reconciliation                            |                  |             
|Income (loss) before
    income taxes              | (4,084)          | 5,364       
|Expected income tax
    expense (recovery)         | (1,710)          | 2,272       
|Increase (decrease) in income taxes resulting      |                  |             
|from
    manufacturing and processing rate         |                  |             
|reduction                                          | 286              | (375)       
|Large
    corporations tax                         | 254              | 235         
|Effect of tax rate
    changes                     | (380)            | 206         
|Income tax expense
    (recovery)                  | (1,550)          | 2,338       
|                                                   |                  |             
|Components of income tax expense (recovery)        |                  |             
|Current
    tax expense (recovery)                 | (117)            | 235         
|Future
    income tax expense related to the       |                  |             
|origination and reversal of temporary differences  | (1,053)          | 1,897       
|Future
    income tax expense (recovery) resulting |                  |             
|from
    change in tax rates                       | (380)            | 206         
|Income
    tax expense (recovery)                  | (1,550)          | 2,338       
|                                                   |                  |             

|                                             | June 30, 2003 | December 31, 2002
|-------------------------------------------- | ------------- | -----------------
|                                             | $             | $                
|Component of future
    income tax liability | (unaudited)   |                  
|                                             |               |                  
|Capital assets                               | 33,777        | 35,233           

A-9

---

The Redwater Natural Gas Liquids Processing
System of 
Williams Energy (Canada), Inc.NOTES TO FINANCIAL STATEMENTS
(Amounts are stated in thousands of Canadian dollars)

June 30, 2003 and December 31, 2002

6.

The following transactions occurred in the normal course of
operations with The Williams Companies Inc. (TWC), the ultimate parent of WECI,
and other companies in the TWC group subject to common control during the period
and were measured at the exchange amounts:

|                                       | Six months ended | Year ended  
|-------------------------------------- | ---------------- | ------------
|                                       | June 30,         | December 31,
|                                       | 2003             | 2002        
|                                       | $                | $           
|                                       | (unaudited)      | (unaudited) 
|                                       |                  |             
|Income statement                       |                  |             
|Sale of
    propane                    | 37,271           | 22,316      
|Net
    settlements of hedges [note 8] | (1,728)          | -           
|Purchase of natural gas                | -                | 5,417       
|                                       |                  |             

|                                   | June 30, 2003 | December 31, 2002
|---------------------------------- | ------------- | -----------------
|                                   | $             | $                
|                                   | (unaudited)   |                  
|Balance sheet                      |               |                  
|Accounts receivable in respect of: |               |                  
|Propane
    sales                  | 7,041         | 10,096           
|Net settlements of
    hedges      | -             | 1,529            
|                                   | 7,041         | 11,625           
|                                   |               |                  
|Account
    payable in respect of: |               |                  
|Net settlement of hedges           | 1,372         | -                
|Natural
    gas purchases          | 1,973         | 9,153            
|                                   | 3,345         | 9,153            
|                                   |               |                  

A-10

---

The Redwater Natural Gas Liquids Processing
System of Williams Energy (Canada), Inc.NOTES TO FINANCIAL STATEMENTS
(Amounts are stated in thousands of Canadian dollars)

June 30, 2003 and December 31, 2002

7.

|                                                                 | June 30, 2003 | December 31, 2002
|---------------------------------------------------------------- | ------------- | -----------------
|                                                                 | $             | $                
|                                                                 | (unaudited)   |                  
|Williams Energy (Canada) Pipelines Inc. equity:                  |               |                  
|Authorized - unlimited number of common shares without par value |               |                  
|Common
    shares                                                | 4,938         | 4,938            
|Deficit                                                          | (1,665)       | (1,338)          
|                                                                 | 3,273         | 3,600            
|WECI's net
    investment in the other Redwater assets           | 190,743       | 173,377          
|WECI's total net
    investment                                  | 194,016       | 176,977          

8. FINANCIAL INSTRUMENTS AND RISK MANAGEMENT a) Commodity price risk
management

Redwater production of natural gas liquids is generally sold under short-term
market based contracts.

b) Hedges

At December 31, 2002 and June 30, 2003, WECI had entered into
swaps with an affiliate to fix the sales price on approximately 10,000 bbls/day
of natural gas liquids produced by Redwater for January of 2003 and July of
2003, respectively. Under the swaps, Redwater receives various fixed prices and
pays floating OPIS prices. The fair market value of the swaps at December 31,
2002 and June 30, 2003 was ($119) and ($241), respectively.

c) Fair values of financial assets and liabilities

The carrying values reported on the balance sheet for accounts receivable,
amounts due from and to affiliates and current liabilities approximate fair
value due to the short-term nature of those instruments.

d) Credit risk

A substantial portion of Redwater's accounts receivable is
with customers in the energy industry and is subject to the normal industry
risks. At June 30, 2003, the accounts receivable from Redwater's three largest
customers amounted to 29%, 17% and 15% of accounts receivable respectively (23%,
16% and 14% at December 31, 2002).

A-11

---

The Redwater Natural Gas Liquids Processing
System of 
Williams Energy (Canada), Inc.NOTES TO FINANCIAL STATEMENTS
(Amounts are stated in thousands of Canadian dollars)

June 30, 2003 and December 31, 2002

9.

|                                         | Six months ended | Year ended 
|---------------------------------------- | ---------------- | -----------
|                                         |                  | June 30,   
|                                         | 2003             | 2002       
|                                         | $                | $          
|                                         | (unaudited)      | (unaudited)
|                                         |                  |            
|Accounts receivable                      | 9,252            | (1,316)    
|Inventories                              | (4,577)          | (3,297)    
|Prepaid
    expenses                     | (783)            | 687        
|Due
    from affiliates                  | 4,584            | 19,613     
|Accounts payable and accrued liabilities | (17,725)         | 6,102      
|Due to affiliates                        | (5,808)          | (453)      
|                                         | (15,057)         | 21,336     

10. COMMITMENTS

Redwater has entered into a 10 year take-or-pay arrangement for the
transportation of natural gas liquids that expires in 2008 and requires annual
minimum payments of $5,475 for the next five years.

At June 30, 2003, WECI's ultimate parent company had
outstanding letter of credit issued on behalf of Redwater amounting to US$20
million. This letter of credit was issued by a bank in favor of a supplier for
Redwater's faithful payment of services rendered in the normal course of
business. The letter of credit expires on August 15, 2003 but was extended to
November 14, 2003 for US$17.5 million.

A-12

---

SCHEDULE B
REPORT ON RESERVES DATA BY INDEPENDENT QUALIFIED 
RESERVES EVALUATOR OR AUDITORApril 2, 2004Provident Energy Ltd. 700, 112 - 4th Avenue S.W. 
Calgary, Alberta 
T2P 0H3
Attention: The Board of Directors of Provident Energy Ltd.
Re:Form
51-101F2 
      Report on Reserves Data by an Independent
Qualified Reserves Evaluator 
      of Provident Energy Ltd. (the "Company")

Dear Sir:

To the Board of Directors of Provident Energy Ltd. (the "Company"):

1. We have evaluated the
  Company's reserves data as at December 31, 2003. The reserves data consists of
  the following:

> (a)
>     proved and proved plus
>     probable oil and gas reserves estimated as at December 31, 2003 using
>     forecast prices and costs and the related estimated future net revenue; and
>     (b)
>     proved and proved plus
>     probable oil and gas reserves estimated as at December 31, 2003 using
>     constant prices and costs and the related estimated future net revenue.

1. The reserves data are the responsibility of the Company's management. Our
  responsibility is to express an opinion on the reserves data based on our
  evaluation.

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

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

B-1

---



1. The
  following table sets forth the estimated future net revenue (before deduction
  of income taxes) attributed to proved plus probable reserves, estimated using
  forecast prices and costs and calculated using a discount rate of 10 percent,
  included in the reserves data of the Company evaluated by us, for the year
  ended December 31, 2003, and identifies the respective portions thereof that
  we have evaluated, audited and reviewed and reported on to the Company's
  management:

|                    |                      | Net Present Value of
    Future Net Revenue $M
|------------------- | -------------------- | ----------------------------------------------
|                    |                      | (before income
    taxes, 10% discount rate)  
|Preparation Date of |                      |                                               
|Evaluation Report   | Location of Reserves | Audited                                       
|                    |                      |                                               
|December 31, 2003   | Canada               | -                                             

1. In our opinion, the reserves data
  evaluated by us have, in all material respects, been determined and are in
  accordance with the COGE Handbook.
2. We have no responsibility to update our report for events and
  circumstances occurring after the preparation date.
3. Because the reserves data are based on judgments regarding future events,
  actual results will vary and the variations may be material.

Executed as to our report referred to above:

MCDANIEL & ASSOCIATES CONSULTANTS LTD.

"signed by W. C. Seth" 
_________________________ 
W. C. Seth, P. Eng. 
President & Managing Director

Calgary, Alberta

B-2

---

SCHEDULE C
REPORT OF MANAGEMENT AND DIRECTORS 
ON RESERVES DATA AND OTHER INFORMATION 
(FORM 51-101F3)Terms to which a meaning is ascribed in National Instrument 51-101 have the
same meaning herein.

Management of Provident Energy Ltd. (the "Company") are
responsible for the preparation and disclosure, or arranging for the preparation
and disclosure of information with respect to the Company's oil and gas
activities in accordance with securities regulatory requirements. This
information includes reserves data, which consist of the following:
(a) (i) Proved and Proved plus probable oil and gas reserves estimated as
  at December 31, 2003 using forecast prices and costs; and
  (ii) the related estimated future net revenue; and
  (b) (i) Proved oil and gas reserves estimated as at December 31, 2003 using
  constant prices and costs; and
  (ii) the related estimated future net revenue.
Independent qualified reserves evaluators have evaluated and
reviewed the Company's reserves data. The report of the independent qualified
reserves evaluators will be filed with securities regulatory authorities
concurrently with this report.
The Reserves, Environment, Health and Safety Committee (the "Reserves
Committee") of the Board of Directors of the Company has:
(a) reviewed the Company's procedures for providing information to the
  independent qualified reserves evaluators;
  (b) met with the independent qualified reserves evaluator(s)
  to determine whether any restrictions affected the ability of the independent
  qualified reserves evaluators to report without reservation; and
  (c) reviewed the reserves data with Management and the independent
  qualified reserves evaluators.
The Reserves Committee of the Board of Directors has reviewed
the Company's procedures for assembling and reporting other information
associated with oil and gas activities and has reviewed that information with
Management. The Board of Directors has, on the recommendation of the Reserves
Committee, approved:
(a) the content and filing with securities regulatory authorities of the
  reserves data and other oil and gas information;
  (b) the filing of the report of the independent qualified reserves
  evaluator(s) on the reserves data; and
  (c) the content and filing of this report.

C-1

---

Because the reserves data are based on judgements regarding future events,
actual results will vary and the variations may be material.
(Signed) Thomas W. BuchananChief Executive Officer
    (Signed) David J. FrickerVice President, Corporate Development
    (Signed) Grant D. Billing 
    Director
    (Signed) Jeffrey T. Smith 
    DirectorApril 19, 2004
C-246 | ANNUAL REPORT 2003William T. Cromb, CAController
      
      Wendy C. Martino, CMA, CFAMidstream Controller
      
      Gary M. Myers, CMAUpstream Controller

The following
analysis provides a detailed explanation of Provident's operating results for
the year ended December 31, 2003 compared to the year ended December 31, 2002
and should be read in conjunction with the audited consolidated financial
statements of Provident.
This disclosure contains certain forward-looking estimates that involve
substantial known and unknown risks and uncertainties, certain of which are
beyond Provident's control, including the impact of general economic conditions
in Canada and the United States; industry conditions; changes in laws and
regulations including the adoption of new environmental laws and regulations and
changes in how they are interpreted and enforced; increased competition; the
lack of availability of qualified personnel or management; fluctuations in
commodity prices; foreign exchange or interest rates; stock market volatility
and obtaining required approvals of regulatory authorities. Provident's actual
results, performance or achievement could differ materially from those expressed
in, or implied by, these forward-looking estimates and, accordingly, no
assurances can be given that any of the events anticipated by the
forward-looking estimates will transpire or occur, or if any of them do so, what
benefits, including the amounts of proceeds, that Provident will derive
therefrom. All amounts are reported in Canadian dollars, unless otherwise
stated. All conversions of natural gas to oil equivalent are on a 6:1 basis.46 | PROVIDENT ENERGY TRUST
ANNUAL REPORT 2003 | 47
Jennifer M.E. Pierce, MA, MBASenior Manager 
      Investor Relations and Communications
Provident Energy Trust has diversified investments in certain segments of the
energy value chain. Provident currently operates in two key business segments:
Oil and Natural Gas Production (OGP) and Midstream Services and Marketing
(Midstream). Provident's OGP business unit produces crude oil and natural gas
from five core areas in the western Canadian sedimentary basin while the
Midstream business unit extracts, transports, fractionates, stores, distributes
and markets NGLs at the Redwater facility and surrounding infrastructure located
north of Edmonton, Alberta, and markets crude oil.
This analysis commences with a summary of the consolidated
financial and operating results followed by segmented reporting on the OGP
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.
Consolidated Cash Flow from
      Operations and Cash Distributions
      Year
      endedDecember 31,2003
      
      2002Revenue, Cash Flow and DistributionsRevenue (net of royalties)
      $
      400,702
      $
      163,508Cash flow from Operations
      $
      135,706
      $
      96,896Per
      weighted average unit - basic1
      $
      1.98
      $
      2.41Interest on convertible debentures
      $
      (7,341)
      $
      (4,901)Adjusted cash flow
      $
      128,365
      $
      91,995Declared distributions
      $
      129,612
      $
      81,526Per
      Unit2
      $
      2.06
      $
      2.03Percent of cash flow distributed
      
      96%
      
      84%Percent of adjusted cash flow distributed
      
      101%
      
      89%1 includes exchangeable
      shares 
      2 excludes exchangeable shares
PROVIDENT ENERGY TRUST |
    4748 | ANNUAL REPORT 2003Cash flow from operations ("cash flow") increased 40 percent to $135.7
million in 2003 from $97.0 million in 2002. The growth in cash flow in 2003
reflected a full year of the oil and gas production acquisitions completed
throughout 2002 as well as fourth quarter cash flow generated by the Midstream
business unit acquired September 30, 2003. Cash flow from OGP increased 31
percent to $126.7 million compared to $97.0 million in 2002. The acquisition
driven increase incorporated a 25 percent increase in production volumes, an
increase in average commodity prices partially offset by opportunity costs from
the Commodity Price Risk Management Program, lower realized prices due to the
appreciating Canadian dollar, as well as increased general and administration
costs and interest expense associated with Provident's growth. Cash flow from
the Midstream business unit included in Provident's results effective September
30, 2003 totaled $9.0 million for the fourth quarter of 2003 with no comparable
figure for 2002. Cash flow from operations per unit decreased 18 percent to
$1.98 per unit compared to $2.41 in 2002. The opportunity cost associated with
the Commodity Price Risk Management Program was significant in 2003 amounting to
$0.71 per unit compared to the cost in 2002 of $0.16 per unit.
Management uses cash flow (before changes in non-cash working
capital) to analyze operating performance and leverage. Cash flow 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. Cash flow 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 cash flow throughout this report are based on cash flow before
changes in non-cash working capital.Adjusted Cash FlowProvident uses the term adjusted cash flow to refer to cash
flow from operations net of the interest paid on the subordinated convertible
debentures. Management reviews adjusted cash flow in setting distributions and
historically has paid out close to all of its adjusted cash flow as
distributions to unitholders. Provident has maintained a high payout ratio of
adjusted cash flow in both 2003 and 2002 as it has funded its annual capital
program through participation in its Premium Distribution, Distribution
Reinvestment and Optional Unit Purchase Plan program and minor property
dispositions. Adjusted cash flow for 2003 was $128.4 million compared to $129.6
million of distributions while in 2002 adjusted cash flow was $92.1 million and
distributions totaled $81.5 million. Distributions were 101 percent of adjusted
cash flow in 2003 and 89 percent in 2002.
  48 | PROVIDENT ENERGY TRUST
ANNUAL REPORT 2003 | 49Distributions
The following table summarizes distributions paid or declared by the Trust
since inception:Distribution AmountRecord Date
    Payment Date
    
    (Cdn$)
    
    (US$)*2003January 21
    February 14
    $
    0.20
    $
    0.13February 20
    March 14
    
    0.20
    
    0.13March 20
    April 15
    
    0.20
    
    0.14April 21
    May 15
    
    0.20
    
    0.15May 20
    June 13
    
    0.20
    
    0.15June 18
    July 15
    
    0.20
    
    0.14July 21
    August 15
    
    0.17
    
    0.12August 20
    September 15
    
    0.15
    
    0.11September 18
    October 15
    
    0.15
    
    0.11October 21
    November 14
    
    0.15
    
    0.11November 19
    December 15
    
    0.12
    
    0.09December 18
    January 15, 2004
    
    0.12
    
    0.092003 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, 2003 -
    Distributions paid as declared
    $
    6.63
    $
    4.40* exchange rate based on the Bank of Canada noon rate on the payment date.For Canadian residents the tax treatment of the distributions was: 2003 - 59
percent taxable, 41 percent return of capital;
2002 - 48 percent taxable, 52 percent return of capital; 2001 - 40.7 percent
taxable, 59.3 percent return of capital.Net Income
Net Income
    
    Year endedDecember 31,(000s except per unit data)
    
    2003
    
    2002Net income
    $
    33,394
    $
    8,340Per
    weighted average unit- basic (1)
    $
    0.38
    $
    0.09Per
    weighted average unit-
    diluted (2)
    $
    0.38
    $
    0.09(1)Based on weighted average number of trust units and trust
units that would be issued upon conversion of exchangeable shares. Net income
available for distribution to unitholders in the basic and diluted per trust
unit calculations has been reduced by interest on the convertible debentures.

(2)Based on weighted average number of trust units and trust units that would be
issued upon conversion of exchangeable shares and conversion of the convertible
debentures.
PROVIDENT ENERGY TRUST |
    49
50 | ANNUAL REPORT 2003Comparative figures for net income have been restated due to
the retroactive application of the new Asset Retirement Obligation accounting
standard. Losses before taxes amounted to $19.8 million for the year, however
future tax recoveries of $56.5 million for the year ended December 31, 2003
resulted in the reported income.
The OGP business segment contributed $126.7 million of cash
flow, $118.0 million of earnings before interest DD&A and taxes, and $25.3
million of net income for the year ended December 31, 2003. The Midstream unit
contributed $9.0 million of cash flow, $10.3 million of earnings before
interest, taxes and depletion, depreciation and accretion, and $8.1 million of
net income for the year ended December 31, 2003.Taxes
    
    Year endedDecember 31,2003
    
    2002Capital taxes
    $
    3,332
    $
    3,264Future income taxes recovery
    $
    (56,478)
    $
    (18,414)Comparative figures for future income taxes (recovery) have been restated due
to the retroactive application of the new
Asset Retirement Obligation accounting standard.
The year to date future income tax recovery was primarily
caused by changes in Canadian tax legislation. On June 9, 2003 the Canadian
government substantially enacted federal income tax changes for the oil and
natural gas sector as it had outlined in its 2003 budget. Resource tax rates
will decline from the current 27 percent to 21 percent by 2007. Concurrently,
the 100 percent deductibility of the resource allowance will be phased out and
Crown charges will become 100 percent deductible. These changes, combined with a
revision in estimates of Provident's tax pool balances, resulted in the
significant future tax recovery.
Capital taxes include the Saskatchewan Resource surcharge and federal and
provincial large corporation taxes.
Interest Expense
    
    Year endedDecember 31,2003
    
    2002Interest on long-term debt
    $
    9,733
    $
    5,307Interest expense increased for the year ended December 31, 2003 as compared
to 2002 due to the increase in the overall size of Provident, with commensurate
increases in debt levels.
Provident continued to manage debt, and in turn interest
expense, prudently in 2003. Capital spending of $31.6 million, excluding the
Redwater purchase, was funded through capital dispositions of $9.9 million and
proceeds from Provident's Premium Distribution, Distribution Reinvestment and
Optional Unit Purchase Plan (the DRIP) of $27.4 million. The Redwater purchase
was financed in part by the $276.6 million bought deal financing that comprised
$201.6 million of unit equity and $75.0 million of convertible debentures.
  50 | PROVIDENT ENERGY TRUST
ANNUAL REPORT 2003 | 51Commodity Price Risk Management ProgramProvident's Commodity Price Risk Management Program involves a disciplined
hedging strategy and use of derivative instruments to mitigate near term price
risk associated with the volatility of commodity prices. 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. Provident uses a combination of forward
sales contracts, physical hedges on both wellhead prices and heavy oil
differentials, financial hedging on WTI crude oil and AECO natural gas prices
and Cdn/US exchange rate hedges. For 2003, the Program recorded an opportunity
cost of $23.9 million on crude oil ($4.77 per barrel) and an opportunity cost of
$25.0 million on natural gas ($0.92 per mcf), compared to an opportunity cost
$13.0 million for crude oil ($3.13 per barrel) and a positive impact of $6.6
million for natural gas ($0.32 per mcf) in 2002. The total impact in 2003 was an
opportunity cost of $48.9 million ($4.91 per boe) compared to an opportunity
cost of $6.4 million ($0.81 per boe) in 2002. In 2003, 46 percent of the
opportunity cost or $22.6 million was realized in the first quarter when the WTI
crude oil price averaged US$33.80 and natural gas priced at AECO averaged
Cdn$7.61 per mcf, quarterly averages that have never before been achieved in
tandem at those levels. On a per unit basis the opportunity costs were $0.71 per
unit in 2003 and $0.16 per unit in 2002.
The estimated mark to market value of open contracts at
December 31, 2003 was negative for both crude oil and natural gas, totaling
$21.1 million for crude oil and $4.1 million for natural gas based on commodity
prices prevailing at December 31, 2003. The contract positions are provided in
note 17 to the consolidated financial statements - Financial instruments and
hedging.Liquidity and Capital Resources
    December 31,2003
    
    2002Long-term debt
    $    
    236,500
    $
    187,200Working capital
    (surplus)/deficit
    (18,552)
    
    15,681Net debt
    217,948
    
    202,881Equity (at book
    value)
    679,228
    
    471,420Total capitalization at book value
    $    
    897,176
    $
    674,301Net debt as a percentage of total
    book value capitalization
    24%
    
    30%Bank Debt and Working CapitalAs at December 31, 2003 Provident had drawn on 80 percent of
its $310.0 million revolving term credit facility, comparable to the 74 percent
drawn at December 31, 2002. At December 31, 2003 Provident had letters of credit
guaranteeing Provident's performance under certain commercial contracts that
totaled $12.3 million, marginally increasing bank line utilization to 80
percent. The guarantees are associated with the marketing segment of the
midstream business unit. At December 31, 2002 Provident's guarantees were
negligible.
Provident's net debt (debt net of working capital) and working capital
increased by $15.1 million to $217.9 million as at December 31, 2003 compared to
$202.9 million as at December 31, 2002. The 2003 year-end working capital
surplus of $18.6 million compares to a $15.7 million deficit at 2002 year end
with the surplus being primarily attributable to the $24.2 million of inventory
associated with the Midstream business unit.
Net debt has decreased to 24 percent of total debt and equity, at book values
from 30 percent for the prior year.
PROVIDENT ENERGY TRUST |
    

    
    51
52 | ANNUAL REPORT 2003Convertible Subordinated Debentures
In April 2002 the trust issued $64.4 million aggregate
principle amount of convertible unsecured subordinated 10.5 percent debentures
(10.5 percent debentures) that mature May 15, 2007 with interest payable
semi-annually in arrears on May 15 and November 15 each year. The 10.5 percent
debentures are convertible at the debenture holder's option into Trust Units at
a conversion price of $10.70 per Trust Unit, subject to adjustment in certain
circumstances. In 2003, $14.4 million of the debentures were converted into
trust units compared to $0.1 million in 2002. Interest recorded on these
debentures in 2003 increased to $5.6 million compared to $4.9 million in 2002
reflecting that the debentures were outstanding throughout 2003 compared to
under nine months in 2002.
On September 30, 2003 the Trust issued $75.0 million aggregate principle
amount of convertible unsecured subordinated 8.75 percent debentures (8.75
percent debentures) that mature December 31, 2008 with interest payable
semi-annually in arrears on June 30 and December 31 in each year commencing
December 31, 2003. The 8.75 percent debentures are convertible at the debenture
holder's option into Trust Units at a conversion price of $11.05 per Trust Unit,
subject to adjustment in certain circumstances. During the three months the
debentures were outstanding, there were no conversions to trust units and the
interest accrued and paid at December 31, 2003 amounted to $1.6 million. The
8.75 percent debentures were issued September 30, 2003 in conjunction with the Redwater acquisition.
The Trust's debentures net of issue costs are currently
classified in Unitholders' Equity as the principal amount of the debentures can
be settled with either trust units or cash at the time of maturity. Interest on
the Debentures is included in Unitholders' Equity as accumulated interest on
convertible debentures.Trust UnitsEffective with the May 2002 distribution, the Trust initiated a premium
distribution, and distribution reinvestment plan ("DRIP"). The DRIP permits
eligible unitholders to direct their distributions to the purchase of additional
units at 95 percent of the average market price as defined in the plan ("Regular
DRIP"). The premium distribution component permits eligible unitholders to elect
to receive 102 percent of the cash the unitholder would otherwise have received
on the distribution date ("Premium DRIP"). Unitholders who participate in either
the Regular DRIP or the Premium DRIP are also eligible to participate in the
optional unit purchase plan as defined in the plan. 2.6 million units were
issued for proceeds of $27.4 million pursuant to this plan during 2003, compared
to 1.8 million units for proceeds of $17.7 million in 2002.
On September 30, 2003, concurrent with the purchase of the
Redwater assets, the trust issued 16,700,000 units, with an additional 2,505,000
units being issued shortly thereafter as the underwriters exercised an
overallotment option for proceeds of $201.7 million. In 2002 the trust issued an
aggregate of 25.7 million units for proceeds of $257.2 million as part of the
Richland and Meota acquisitions, and a further 3.9 million units (proceeds $39.4
million) were issued to partially finance a major property purchase.
During the year ended December 31, 2003 the Trust issued 5.7
million units on conversion of exchangeable shares to units (conversion amount
$55.5 million) (2002 - 0.6 million units issued with a conversion amount of $6.9
million), and 1.3 million units issued on conversion of convertible debentures
(conversion amount $14.4 million) (2002 - 0.012 million units issued with a
conversion amount of $0.13 million).
  52 | PROVIDENT ENERGY TRUSTANNUAL REPORT 2003 | 53On February 4, 2004 the Trust issued 4.5 million units at
$11.20 per unit for proceeds of $50.4 million ($47.9 million net of issue costs)
pursuant to a public offering prospectus dated January 22, 2004. Proceeds from
the issue were initially used to pay down Provident's bank debt and throughout
2004 will be used to finance the board approved 2004 capital budget of $46.0
million.Capital Expenditures and Funding
    
    Year endedDecember 31,2003
    
    2002Capital
    ExpendituresCapital expenditures and site restoration
    $
    (34,120)
    $
    (23,297)Property acquisitions
    
    -
    
    (70,936)Acquisition of Redwater
    (298,638)
    
    -Corporate acquisitions
    
    (364)
    
    (35,530)Property dispositions
    
    9,947
    
    11,157Net capital
    expenditures
    $ (323,175)
    $
    (118,606)Funded ByAdjusted cash flow net of declared distributions
    $
    (1,247)
    
    $10,469Issue
    of debentures, net of cost
    
    71,800
    
    61,398Issue
    of trust units, net of cost; excluding DRIP
    
    192,854
    
    38,270DRIP
    proceeds
    
    27,408
    
    17,744Reimbursements - leasehold improvements
    
    1,437
    
    -Change
    in working capital
    
    (18,377)
    
    1,050Increase (decrease) in
    long term bank debt
    
    49,300
    
    (10,325)$
    323,175
    $
    118,606The acquisition of the Redwater assets was funded by the
issue of equity and convertible debentures and bank debt. Bank debt of $100.0
million has been allocated to the midstream assets in the segmented reporting in
the financial statements. Capital expenditures were funded by a combination of
DRIP proceeds and proceeds received on non-core property dispositions.
Provident's strategy is to fund acquisitions by accessing the capital markets
and to fund capital expenditures through DRIP and other equity if needed.Net Asset ValueProvident's net asset value ("NAV") at January 1, 2004 is
summarized in the table below. The net asset value is calculated on a fully
diluted basis, which includes exchangeable shares and unit options, and
presented with two discounted cash flow cases with the convertible debentures
treated as equity and debt.
PROVIDENT ENERGY TRUST |
    

    
5354 | ANNUAL REPORT 2003
McDaniel
    
    McDaniel(Jan 1, 2004 Pricing)
    
    (April 1, 2004 Pricing)At January 1, 2004
    Discounted
    Discounted
    
    Discounted
    Discounted($000s, except for unit date)
    at 10 percent
    at 8 percent
    at 10 percent
    at 8 percentPresent value of
    proved plus probableoil
    and natural gas reserves
    $
    418,422(1)
    $
    444,392(1)
    $
    500,961(2)
    $
    530,244(2)Midstream assets
    (3)
    
    345,083
    
    395,864
    
    345,083
    
    395,864Undeveloped land
    (4)
    
    28,016
    
    28,016
    
    28,016
    
    28,016Unit Option
    proceeds
    
    44,340
    
    44,340
    
    44,340
    
    44,340Net debt including working capital
    
    (217,948)
    
    (217,948)
    
    (217,948)
    
    (217,948)Net asset value
    $
    617,913
    $
    694,664
    $
    700,452
    $
    780,516Units Fully Diluted (thousands)
    
    100,315
    
    100,315
    
    100,315
    
    100,315NAV per unit
    $
    6.16
    $
    6.92
    $
    6.98
    $
    7.78NAV per unit (debentures as debt)
    $
    5.55
    $
    6.41
    $
    6.48
    $
    7.38(1)Evaluated by McDaniel & Associates Consultants Ltd. effective January 1,
2004: includes hedging 
(2)Evaluated by McDaniel & Associates Consultants Ltd. effective April 1, 2004:
includes hedging.
(3)The midstream assets were acquired on September 30, 2003 for CDN$283.2
million plus inventory. Discounted cash flows were determined using annual
EBIDTA of $38MM for 20 years 
(4)Evaluated by Seaton-Jordon & Associates Ltd. effective January 1, 2004OGP Segment Review
Crude oil price
    
    Year endedDecember 31,2003
    
    2002
    % changeOil per barrelWTI
    (US$)
    $
    31.02
    $
    26.11
    19Exchange rate (from US$ to Cdn$)
    $
    1.41
    $
    1.56
    (10)WTI
    expressed in Cdn$
    $
    43.74
    $
    40.73
    7Corporate realized crude oil and naturalgas liquids price before hedging (Cdn$)
    $
    30.77
    $
    29.62
    4Corporate realized light/medium oilprice before hedging (Cdn$)
    $
    36.02
    $
    34.90
    3Corporate realized heavy oil pricebefore hedging (Cdn$)
    $
    24.74
    $
    25.46
    (3)Corporate realized natural gas liquidsprice before hedging (Cdn$)
    $
    35.87
    $
    29.04
    24For 2003, the 19 percent increase in WTI did not lead to a commensurate
increase in Provident's realized oil and natural gas liquids price, prior to the
impact of hedging, as Provident's price was eroded by the stronger Canadian
dollar partially offset by a decreased percentage of production of lower priced
heavy oil. Heavy oil production as a percentage of total crude oil and natural
gas liquids production in 2003 was 46 percent compared to 51 percent in 2002.
The decrease in the year over year percentage of heavy oil production was mainly
due to the October 1, 2002 Meota Resources Corp. acquisition that added a higher
percentage of light oil to Provident's overall liquids production mix in the
fourth quarter of 2002 and throughout all of 2003.
  54 | PROVIDENT ENERGY TRUSTANNUAL REPORT 2003 | 55
Natural gas
    price
    
    
    Year endedDecember 31,2003
    
    2002
    % changeAECO (Cdn$)
    $
    6.69
    $
    4.05
    65Gas revenue per mcf (1)
    (Cdn$)
    $
    6.63
    $
    4.35
    52(1)Excluding the effects of the commodity price risk management programProvident's realized natural gas price, excluding hedges, increased 52
percent over 2002, reflecting very strong gas prices throughout the year.
Production
    
    Year
    endedDecember 31,2003
    2002
    % changeDaily productionCrude oil -
    Light/Medium (bpd)
    6,812
    5,096
    34- Heavy (bpd)
    6,902
    6,310
    9Natural gas liquids
    (bpd)
    1,167
    1,030
    13Natural gas (mcfd)
    74,596
    56,193
    33Oil equivalent (boed) (1)
    27,314
    21,801
    25(1)Provident reports equivalent production converting natural gas to oil on a
6:1 basis.The 25 percent increase in 2003 production to average 27,314
boed compared to 21,801 boed in 2002 is primarily attributable to production
associated with acquisitions closed in 2002 that were incorporated in
Provident's production averages for a full year in 2003.
Provident's 2003 drilling program coupled with other
production optimization activities, added approximately 3,200 boed of initial
production primarily from the Lloydminster core area. The 2003 drilling program
production additions have offset natural gas and natural gas liquids production
declines in West Central Alberta at Brazeau and Gilby.
The 2003 daily production mix was 46 percent natural gas, 25
percent conventional heavy oil and 29 percent medium/light crude oil and natural
gas liquids. The mix was relatively unchanged from the 2002 production mix of 43
percent natural gas, 29 percent conventional heavy oil and 28 percent
medium/light crude oil and natural gas liquids. No single property within
Provident's portfolio exceeds 10 percent of daily production.
Provident's $46.0 million, 2004 board approved capital budget
will focus primarily on shallow gas opportunities in Southern Alberta and
Southern Saskatchewan. The production adds forecasted with the anticipated
capital spending offset by natural production declines results in estimated
average production for 2004 of 24,300 boed.
PROVIDENT ENERGY TRUST |
    

    
5556 | ANNUAL REPORT 2003
Revenue and
    royalties
    
    
    Year endedDecember 31,2003
    
    2002
    %
    changeOilRevenue
    $
    151,874
    $
    123,543
    23Cash
    hedging
    
    (23,892)
    
    (13,029)
    83Royalties (net of ARTC)
    
    (29,156)
    
    (22,469)
    30Net revenue
    $
    98,826
    $
    88,045
    12Net
    revenue (per barrel)
    $
    19.74
    $
    21.15
    (7)Royalties as a percentage of revenue
    
    19.2%
    
    18.2%
    5Natural gasRevenue
    $
    180,590
    $
    89,131
    103Cash
    hedging
    
    (25,042)
    
    6,550
    -Amortization of deferred hedging
    
    (827)
    
    (9,477)
    91Royalties (net of ARTC)
    
    (39,190)
    
    (19,191)
    104Net revenue
    $
    115,531
    $
    67,013
    72Net
    revenue (per mcf)
    $
    4.24
    $
    3.27
    30Royalties as a percentage of revenue
    
    21.7%
    
    21.5%
    1Natural gas liquidsRevenue
    $
    15,282
    $
    10,915
    40Royalties
    
    (4,523)
    
    (2,654)
    70Net revenue
    $
    10,759
    $
    8,261
    30Net
    revenue (per barrel)
    $
    25.25
    $
    21.98
    15Royalties as a percentage of revenue
    
    29.6%
    
    24.3%
    22TotalRevenue
    $
    347,746
    $
    223,589
    56Cash
    hedging
    
    (48,934)
    
    (6,479)
    655Amortization of deferred hedging
    
    (827)
    
    (9,477)
    91Royalties (net of ARTC)
    
    (72,869)
    
    (44,314)
    64Net revenue
    $
    225,116
    $
    163,319
    38Net
    revenue per boe
    $
    22.58
    $
    20.52
    10Royalties as a percentage of revenue
    
    21.0%
    
    19.8%
    6Year over year, crude oil, natural gas and natural gas liquids revenue have
increased primarily due to acquisitions closed in 2002 that were incorporated in
Provident's revenue for the full year in 2003.
The royalty burdens for 2003, expressed as a percentage of
gross revenues, increased to 21 percent from 20 percent in 2002 due to the fact
the percentage royalty paid increases as commodity prices increase and the
increase in natural gas as a percentage of Provident's production mix. Natural
gas generally bears higher royalty rates than royalties on crude oil. In the
future Provident's royalty rates will be dependent on its production mix and
movements in commodity prices.
  56 | PROVIDENT ENERGY TRUSTANNUAL REPORT 2003 | 57
Production
    expenses
    
    
    Year endedDecember 31,2003
    
    2002
    % changeProduction expenses
    $
    76,396
    $
    52,741
    45Production expenses (per boe)
    $
    7.66
    $
    6.63
    16Production expenses increased 45 percent to $76.4 million
from $52.7 million in 2002. The increase was due to the 25 percent increase in
daily average production volumes year over year. On a boe basis in 2003,
production expenses increased each quarter reflecting declining production
volumes bearing the fixed cost component of operating costs over fewer barrels
of oil equivalent production. Further, higher costs for electricity, propane,
processing fees and equalization costs and increased servicing and workover
costs contributed to the 16 percent increase in per boe operating expenses. The
year over year increase in per boe operating costs is consistent with
Provident's peers and industry trends. Operating costs for 2004 are forecast to
average in the range of $7.50 - $8.00 per boe.Other incomeOther income in 2003 of $1.5 million primarily results from a gain realized
on the sale of investments.
General and
    administrative
    
    
    Year endedDecember 31,Canadian dollars (000s except per
    unit data)
    
    2003
    
    2002
    % changeGeneral and
    administrative
    $
    14,289
    $
    7,987
    79Management fees
    $
    -
    $
    11,296
    (100)General and
    administrativeand management fees
    per boe
    $
    1.43
    $
    2.42
    (41)General and administrative and management fee expenses for
2003 were reduced by 26 percent or $5.0 million to $14.3 million from $19.3
million in 2002. On a boe basis the 2003 costs were 41 percent lower at $1.43
per boe compared to $2.42 per boe in 2002. There were no cash management fees
incurred in 2003 as the contract was internalized on January 17, 2003. This
compared to 2002 management fees of $11.3 million of which $6.3 million was
satisfied in cash and $5.0 million was paid in trust units.
For 2004, factoring in anticipated results from the expenditure of the board
approved capital budget, general and administrative expenses for OGP are
expected to trend in the $1.75 per boe range.
PROVIDENT ENERGY TRUST |
    

    
5758 | ANNUAL REPORT 2003
Operating
    netback
    
    
    Year endedDecember 31,2003
    
    2002
    % changeNetback per boeGross production
    revenue
    $
    35.07
    $
    28.10
    26Cash hedging
    
    (4.91)
    
    (0.81)
    506Realized revenue
    
    30.16
    
    27.29
    11Royalties (net of
    ARTC)
    
    (7.31)
    
    (5.57)
    31Operating costs
    
    (7.66)
    
    (6.63)
    16$
    15.19
    $
    15.09
    1The 2003 operating netback of $15.19 per boe was flat to the
$15.09 per boe netback in 2002, however, the components of the operating netback
differ. Higher gross production revenue was offset by increased opportunity
costs associated with the commodity price risk management program, increased
royalties as a percentage of the realized price and higher operating costs than
in 2002.
In 2004 Provident will continue to focus on managing or reducing operating
costs to improve operating netbacks.
Depletion,
    depreciation and accretion (DD&A)
    
    Year endedDecember 31,Canadian dollars (000s except per
    unit data)
    
    2003
    
    2002DD&A
    $
    136,066
    $
    92,987DD&A per boe
    $
    13.65
    $
    11.64The high DD&A rate is attributable to the method of
accounting for corporate acquisitions required under Canadian GAAP. More
specifically, the book value of property, plant and equipment is increased by
the tax-effected difference between the fair value of assets acquired and tax
pools acquired. Over time, the increased DD&A rate is offset by a future tax
recovery.
The main reason for the year over year increase in DD&A rates was the fourth
quarter 2002 Meota acquisition and the tax
effected increase in assets acquired being reflected throughout 2003 compared
to the fourth quarter of 2002.
DD&A includes accretion expense associated with asset retirement obligation
of $2.2 million in 2003 (2002 - $1.7 million).
Capital
    expenditures
    
    Year endedDecember 31,Canadian dollars (000s)
    
    2003
    
    2002Lloydminster
    $
    12,200
    $
    9,670West central and
    southern Alberta
    
    11,936
    
    7,497Southeast and
    southwest Saskatchewan
    
    3,854
    
    3,158Office and other
    
    3,638
    
    1,065Total additions
    $
    31,628
    $
    21,390Dispositions
    $
    9,947
    $
    11,157
  58 | PROVIDENT ENERGY TRUSTANNUAL REPORT 2003 | 59Provident's capital expenditures are primarily funded through
the Premium Distribution, Distribution Reinvestment and Optional Unit Purchase
Plan (DRIP). The DRIP program allows investors to reinvest distributions into
Trust Units. Provident directs proceeds from the DRIP program ($27.4 million),
along with the proceeds from asset dispositions, towards the capital expenditure
budget.
Provident incurred capital expenditures of $31.6 million in
2003, of which $12.2 million was spent in the Lloydminster core area drilling
and completing 28 net heavy oil wells as well as on land purchases and seismic
activity. In Southeast and Southwest Saskatchewan expenditures of $3.9 million
were directed at drilling, re-completions, facility projects as well as land
purchases for future development. In West Central and Southern Alberta $11.9
million was spent on both operated and non-operated drilling projects as well as
on several re-completion, optimization, facility projects and land purchases for
future development. Spending on leasehold improvements and office related
capital primarily associated with Provident's head office move, as well as
capital spending in non-core areas totaled $3.6 million. A total of $1.4 million
of a leasehold improvement allowance was received from the landlord in the year
and a further portion of the spending on office related capital will result in
future rent reductions.
In the year Provident disposed of $9.9 million of assets primarily related to
the sale of acreage, along with minimal production, to a public Canadian junior
oil and gas company. Management considered the risk associated with future
development expenditures on the acreage disposed of to be too high for Provident
to undertake such development activities. The proceeds on disposition were used
to fund a portion of Provident's 2003 capital program.
Provident incurred $21.4 million in capital expenditures in
2002 including $12.4 million on drilling projects primarily in the Lloydminster
core area, $8.4 million of facility costs and $0.6 million of miscellaneous
projects. In addition to the $21.4 million of capital spending, Provident also
acquired Southern Alberta properties in 2002 for $72.0 million.
The capital budget approved by the Board of Directors for 2004 for the OGP
segment is $46.0 million.Midstream Services and MarketingOn September 30, 2003, Provident acquired Western Canadian midstream assets
("Redwater") for $298.6 million. The purchase price was financed through $35.8
million of long-term debt, $71.8 million of net proceeds from the issuance of
convertible debentures, and $191.1 million in net proceeds from the issuance of
19,205,000 trust units.
Provident allocated the purchase price of Redwater as follows:Net assets
    acquired:Petroleum product inventory
    
    
    $
    15,413Property, plant and
    equipment (includes acquisition costs of $6,763)
    
    283,225$
    298,638The acquisition was
    financed by:Long-term debt
    
    
    $
    35,768Issuance of trust units (net of costs $10,582)
    
    191,070Issuance of
    convertible debentures (net of costs $3,200)
    
    71,800$
    298,638
PROVIDENT ENERGY TRUST |
    
    59
60 | ANNUAL REPORT 2003The assetsThe Midstream business unit processes natural gas liquids (NGL) at the
Redwater fractionation, storage and transportation facility located near
Edmonton, Alberta. The integrated Redwater system is comprised of three core
assets:
bullet
    100 percent ownership of the Redwater NGL Fractionation
  Facility, a 65,000 barrels per day (bbl/d) fractionation, storage and
  transportation facility that includes 12 pipeline receipt and delivery points,
  railcar loading facilities with access to CN and CP rail, two propane truck
  loading facilities, and six million gross barrels of salt cavern storage. The
  facility can process high-sulphur NGL streams and is one of only two
  facilities in western Canada capable of extracting ethane from the natural gas
  liquids stream.bullet
    43.3 percent ownership of the 38,500 bbl/d Younger NGL extraction plant
  located at Taylor in northeastern British Columbia that supplies 16,700 bbl/d
  of net NGLs for processing at Redwater.bullet
    100 percent ownership of the 565 kilometre proprietary Liquids Gathering
  System 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.The majority of the property, plant and equipment are depreciated over 30
years on a straight-line basis reflecting the
long useful life of these assets. The 2004 board approved capital budget is
$1.0 million.Midstream servicesProvident's midstream services offers customers several types of services and
contractual arrangements which include:
Fee for service processing - ("Transportation and Fractionation - T&F"): In
these arrangements, NGL owners (typically natural gas producers) deliver to
Provident their NGLs and pay fees for the transportation, processing,
fractionation, storage and distribution of their NGL barrels and are responsible
for the marketing of their product.
Fixed margin processing: This service involves NGL owners
delivering their product to Provident with Provident taking title and paying the
NGL owner an amount that is the difference between a delivery price of raw NGLs
that is discounted to postings and the posted price in that month for the
finished products (this is the "fixed margin") . The discounted price that
Provident purchases the product for covers the costs of transportation,
processing, fractionation, storage, marketing and distribution of the NGLs.
Storage: NGL owners pay fees to store their NGLs.
Transport and Distribution: NGL owners pay fees to transport NGLs through the
LGS pipeline and use rail and truck
loading facilities.The contractsAt the Redwater facility, 97 percent of the available
capacity is contracted through fee-for-service and fixed margin contracts with
major oil and natural gas producers and petrochemical businesses. These
contracts account for 93 percent of Midstream Services's total revenue and as a
result of these contracts, 67 percent of Redwater's output is contracted for 10
years or longer.
  60 | PROVIDENT ENERGY TRUSTANNUAL REPORT 2003 | 61Fractionation plant capacity and throughputThe Redwater facility was constructed between 1996 and 1998.
It is the most modern facility of its type in Canada and is currently designed
for throughput capacity of 65,000 bpd of NGLs with an expectation to average
approximately 63,000 bpd. Plant throughput for the fourth quarter of 2003
averaged 63,616 bpd.RevenuesFourth quarter product sales and services revenues of $143.0
million include T&F processing, fixed margin processing and revenues generated
through storage and distribution services and $30.4 million associated with
crude oil marketing. The majority of NGL revenues are earned pursuant to the
long-term contracts and annual evergreen purchase and sales commitments.Cost of goods soldThe cost of goods sold of $178.0 million for the year relates
to NGL product sales revenue included in the product sales and services revenue,
where Provident has purchased the natural gas liquids and also includes the cost
of crude oil barrels purchased as part of the crude oil marketing business. The
NGL costs would be applicable to the fixed margin contracts and a small
percentage of volume delivered from the Younger facility on which Provident
retains fractionation risk. The majority of the natural gas liquids are
purchased pursuant to long-term contracts and annual evergreen purchase
commitments.Other expensesThe plant has modern technology and low cost operations
compared to other existing North American facilities of this type. Operating
costs of $7.6 million were representative of normal operations for the quarter
without any major turnarounds or operating difficulties. General and
administrative expenses of $1.1 million, interest of $1.1 million, and
depreciation of $2.2 million for the quarter are estimated by management to also
be representative of normal operations for a quarter.Crude oil marketingIn July 2003 Provident initiated operations in its crude oil
marketing business. During the year $29.1 million revenue was generated from
marketing crude oil for third party producers. For the fourth quarter, $16.8
million of revenue was generated marketing third party volumes. Management
estimates that marketing of third party volumes, combined with certain Provident
crude oil volumes, will provide better producer netbacks than can be achieved
through third party marketers.Foreign OwnershipOn September 17, 2003 Canadian unitholders approved an amendment to its 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.
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
inter-company debt. 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. Please see page 91 for proposed changes to the Canadian
Income Tax Act.
PROVIDENT ENERGY TRUST |
    

    
6162 | ANNUAL REPORT 2003Management Internalization
On January 17, 2003, unitholders of Provident approved a management
internalization transaction to eliminate the performance-based arrangement
between external management and the Trust for total non-cash consideration of
$18.0 million plus $0.6 million of transaction costs. Total non-cash
consideration of $18.0 million was settled with the issuance of 1,682,242
exchangeable shares at a deemed price of $10.70 per share that are held in
escrow and released 25 percent per year commencing June 2003. The
internalization was accretive to cash flow and net asset value and also improves
the long-term cost structure of the Trust, which will be beneficial to the
Trust's ability to attract capital in a competitive marketplace and complete
accretive acquisitions. The transaction also increased ownership of the units
held by management and directors further aligning management's interests with
those of unitholders.
At December 31, 2003 approximately 3.5 percent of the outstanding units and
units issuable upon conversion of exchangeable shares were held by management and directors.Business ProspectsProvident intends to execute a balanced portfolio strategy. In the OGP
business internal development projects with a board approved capital budget of
$46.0 million are planned. Halo acquisitions of interest in properties close to
properties already owned or partially owned by Provident will be pursued. Major
corporate or property acquisitions are being evaluated. In the Midstream
Services business Provident will expand and build upon the Redwater business and
evaluate additional infrastructure assets with a goal of adding quality assets
at reasonable prices. The goal of these strategies is to maintain and increase
per unit distributable cash flow and net asset value.SensitivitiesThe following table shows the estimated sensitivity of 2004 cash flows to
changes in pricing, interest and volume with the assets and hedge positions in
place:Change(000s)
    
    per unitPricingWTI
    (+US$ 1.00) Oil
    $
    500
    $
    0.0059AECO
    (+Cdn$ 0.25) Gas
    $
    4,200
    $
    0.0474Interest (+1.0%)
    $
    2,400
    $
    0.0266US exchange (+Cdn$
    0.01)
    $
    500
    $
    0.0061VolumeLight
    / Medium Oil (+100 bpd)
    $
    700
    $
    0.0079Heavy
    Oil (+100 bpd)
    $
    500
    $
    0.0052Natural Gas (+1.0
    mmcfd)
    $
    1,400
    $
    0.0154Critical Accounting PoliciesProvident'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 and also require management to make judgments and
estimates based on conditions and assumptions that are inherently uncertain.
  62 | PROVIDENT ENERGY TRUSTANNUAL REPORT 2003 | 63These 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 equipmentProvident 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 ceiling test limits the carrying value of oil and natural
gas assets, net of future income taxes and asset retirement obligation, to the
estimated undiscounted future net production revenue associated with the proved
oil and natural gas reserves, plus the unimpaired costs of unproved properties,
less estimated future general and administrative expenses, interest and income
taxes.
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 reserves.
Estimates of future production, oil and natural gas prices and future costs
used in the ceiling test are, by their very nature,
subject to uncertainty and changes in underlying assumptions could have a
material impact on Provident's financial results.Asset retirement obligationThe new Canadian Institute of Chartered Accountants ("CICA") standard for
Asset Retirement Obligations changes the method of accounting for certain site
restoration costs. Under the new standard, the fair value of asset retirement
obligations are recorded as liabilities on a discounted basis, when incurred.
The value of the related assets are 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 financials results.
PROVIDENT ENERGY TRUST | 6364 | ANNUAL REPORT 2003Changes in Accounting Policy
The following changes in accounting policy were adopted by Provident in 2003.Asset retirement obligationIn 2003, the CICA issued Handbook Section 3110, Asset Retirement Obligation (ARO).
The new standard requires recognition of the liability associated with future
site reclamation costs at the time the liability is incurred. The new standard
is effective for fiscal years beginning on or after January 1, 2004, however
early adoption is encouraged. Provident early adopted ARO in accordance with the
adoption provisions of the standard.
The ARO standard requires retroactive application with restatement of
comparative periods. Pursuant to the requirement
2002 comparative numbers have been restated to reflect the impact of the new
standard.
For a review of the impact of ARO on Provident's consolidated financial
statements please see Note 3 to the consolidated
financial statements, "Changes in accounting policy."Unit based compensationIn 2003, Provident adopted CICA Handbook section 3870,
"Stock-based compensation and other stock based payments". This change in
accounting policy has been applied prospectively. For a review of the impact of
section 3870 on Provident's consolidated financial statements please see Note 3
to the consolidated financial statements "changes in accounting policy".Recent Accounting PronouncementsThe following new accounting guidelines or standards are applicable to
Provident but have not been implemented.Full cost accountingIn 2003, the CICA issued accounting guideline 16, "Oil and
Gas Accounting - Full Cost." This accounting guideline replaces accounting
guideline 5, "Full cost accounting in the oil and gas industry." The guideline
alters the ceiling test calculation and is effective for fiscal years beginning
on or after January 1, 2004. Provident is currently assessing the impact of this
standard on its financial statements.Exchangeable sharesIn 2003, the CICA issued a draft EIC, "Income trusts - exchangeable shares."
The EIC proposes that the retained interest of the exchangeable shareholders
should be presented on the balance sheet as a non-controlling interest separate
and distinct from unitholders' equity. The draft EIC is currently under review
and was not enacted in final form as of the time of publication of Provident's
consolidated financial statements.Convertible debenturesIn 2005, in accordance with CICA Handbook section 3860, "Financial
instruments - disclosure and presentation," convertible debentures will be
required to be classified as a liability on the balance sheet with interest
payment recorded as an expense. Provident currently records convertible
debentures as unitholders' equity and interest payments on convertible
debentures as reductions to unitholders' equity. If convertible debentures are
outstanding in 2005, the effect of this standard will increase debt, reduce unitholders' equity by the amount of such balances, and decrease income by the
amount of the interest payments.
  64 | PROVIDENT ENERGY TRUSTANNUAL REPORT 2003 | 65Hedging relationshipsCICA accounting guideline 13, "Hedging relationships" is effective for fiscal
periods beginning on or after July 1, 2003. This accounting guideline addresses
the identification, designation, documentation and effectiveness of hedging
relationships, for the purpose of applying hedge accounting. In addition, it
establishes criteria for discontinuing the use of hedge accounting. Under
accounting guideline 13, hedging transactions must be documented and it must be
demonstrated that the hedges are sufficiently effective to continue accrual
accounting for positions hedged with derivatives. Provident does not anticipate
applying hedge accounting to its commodity price risk management program and
will consequently adjust the carrying value of derivatives to market value.Business RisksThe oil and natural gas trust 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:
bullet
    fluctuations in commodity price, exchange rates and interest rates;bullet
    government and regulatory risk in respect of royalty and income tax
  regimes;bullet
    operational risks that may affect the quality and recoverability of
  reserves;bullet
    geological risk associated with accessing and recovering new quantities of
  reserves;bullet
    transportation risk in respect of the ability to transport oil and natural
  gas to market;bullet
    and capital markets risk and the ability to finance future growth.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:
bullet
    operational matters and hazards including the breakdown or failure of
  equipment, information systems or processes;bullet
    the performance of equipment at levels below those originally intended;bullet
    operator error;bullet
    labour disputes;bullet
    disputes with owners of interconnected facilities and carriers and
  catastrophic events such as natural disasters, fires, explosions, fractures,
  acts of eco-terrorists and saboteurs, andbullet
    other similar events, many of which are beyond the control of the Trust or
  Provident.The Midstream NGL assets are subject to competition from
other NGL 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
natural gas products marketing business is subject to competition from other
marketing firms.
Provident strives to minimize these business risks by:
bullet
    employing and empowering management and technical staff with extensive
  industry experience;bullet
    adhering to a strategy of acquiring, developing and optimizing quality,
  low-risk reserves in areas where we have technical and operational expertise;PROVIDENT ENERGY TRUST |
    
    
    
    6566 | ANNUAL REPORT 2003bullet
    developing a diversified, balanced asset portfolio that generally offers
  developed operational infrastructure, year-round access and close proximity to
  markets;bullet
    adhering to a consistent and disciplined Commodity Price Risk Management
  Program to mitigate the impact that volatile commodity prices have on cash
  flow available for distribution;bullet
    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;bullet
    marketing natural gas liquids and related services to selected, credit
  worthy customers at competitive rates;bullet
    maintaining a low cost structure to maximize cash flow and profitability;bullet
    maintaining prudent financial leverage and developing strong relationships
  with the investment community and capital providers;bullet
    adhering to strict guidelines and reporting requirements with respect to
  environmental, health and safety practices; andbullet
    maintaining an adequate level of property, casualty, comprehensive and
  directors' and officers' insurance coverage.Risks Associated With the Level of Foreign OwnershipOn September 17, 2003, Unitholders approved certain
amendments to the Trust Indenture to provide that residency restriction
provisions need not be enforced while the Trust is entitled to rely on the
provisions of paragraph 132(7)(a) of the Tax Act for the purposes of maintaining
its "mutual fund trust" status. The amendments provide that if at any time the
board of directors of Provident determines or becomes aware that the Trust's
ability to continue to qualify as a "mutual fund trust" based on its asset
composition in accordance with paragraph 132(7)(a) of the Tax Act is in
jeopardy, then forthwith after such determination (i) the Trust shall not be
maintained primarily for the benefit of non-residents of Canada and (ii)
Provident shall take such steps as are necessary or desirable to ensure that the
Trust is not maintained primarily for the benefit of non-residents of Canada.
The retention of "mutual fund trust" status under the Tax Act is important
for both resident and non-resident holders of Trust Units and not just for
holders of Trust units held within Canadian tax exempt plans. The loss of such
status could be expected to have an effect on the market price of the Trust
Units. Please see page 91 for proposed changes to the Canadian Income Tax Act.Unit Trading ActivityThe following table summarizes the unit trading activity of the Provident
units for the year ended December 31, 2003 on both the Toronto Stock Exchange
and the American Stock Exchange:
Q1
    
    Q2
    
    Q3
    
    Q4
    
    YTDTSE - PVE.UN (Cdn$)High
    $
    11.95
    $
    12.75
    $
    11.83
    $
    11.75
    $
    12.75Low
    $
    9.85
    $
    10.00
    $
    10.45
    $
    10.28
    $
    9.85Close
    $
    10.29
    $
    10.82
    $
    10.51
    $
    11.43
    $
    11.43Volume (000s)
    
    19,001
    
    25,075
    
    24,068
    
    22,012
    
    90,156AMEX - PVX (US$)High
    $
    8.24
    $
    9.47
    $
    8.53
    $
    8.89
    $
    9.47Low
    $
    6.60
    $
    6.75
    $
    7.70
    $
    7.81
    $
    6.60Close
    $
    7.01
    $
    8.06
    $
    7.82
    $
    8.84
    $
    8.84Volume (000s)
    
    22,625
    
    45,502
    
    30,524
    
    40,261
    
    138,912
  66 | PROVIDENT ENERGY TRUSTANNUAL REPORT 2003 | 67
Quarterly Table
    
    
    
    
    2003First
    Second
    
    Third
    
    Fourth
    
    YTD($000s except per
    unit amounts)
    
    Quarter
    Quarter
    
    Quarter
    
    Quarter
    
    TotalFinancial - consolidatedRevenue
    $
    65,639
    $    
    56,078
    $
    66,375
    $
    212,610
    $
    400,702Cash flow
    $
    41,961
    $    
    31,571
    $
    28,866
    $
    33,308
    $
    135,706Net income
    $
    (8,743)
    $    
    23,073
    $
    (2,003)
    $
    21,067
    $
    33,394Unitholder distributions
    $
    33,091
    $    
    35,528
    $
    28,969
    $
    32,023
    $
    129,611Distributions per unit
    $
    0.60
    $        
    0.60
    $
    0.47
    $
    0.39
    $
    2.06Oil
    and gas productionRevenue
    $
    65,639
    $    
    56,078
    $
    54,013
    $
    52,781
    $
    228,511Earnings before interest, DD&A and taxes
    $
    26,845
    $    
    33,989
    $
    31,517
    $
    25,660
    $
    118,011Cash flow
    $
    41,961
    $    
    31,571
    $
    28,785
    $
    24,385
    $
    126,702Net income (loss)
    $
    (8,743)
    $    
    23,073
    $
    (2,003)
    $
    12,947
    $
    25,274Midstream services and marketing (1)Revenue
    $
    -
    $             
    -
    $
    23,713
    $
    173,435
    $
    197,148Earnings before interest, DD&A and taxes
    $
    -
    $             
    -
    $
    81
    $
    10,243
    $
    10,324Cash flow
    $
    -
    $             
    -
    $
    81
    $
    8,923
    $
    9,004Net
    income
    $
    -
    $             
    -
    $
    81
    $
    8,039
    $
    8,120OperatingOil
    and gas productionLight/medium oil (bpd)
    
    7,285
    6,770
    
    6,748
    
    6,454
    
    6,812Heavy oil (bpd)
    
    6,245
    6,700
    
    7,495
    
    7,151
    
    6,902Natural gas liquids (bpd)
    
    1,085
    1,162
    
    1,276
    
    1,145
    
    1,167Natural gas (mcfd)
    
    83,924
    72,898
    
    73,090
    
    68,657
    
    74,596Oil equivalent (boed)
    
    28,602
    26,781
    
    27,701
    
    26,193
    
    27,314Midstream services and marketingRedwater throughput (bpd)
    
    -
    -
    
    -
    
    63,616
    
    N/AAverage selling price (Cdn $)Light/medium oil per bbl (before hedges)
    $
    43.64
    $      
    33.57
    $
    33.49
    $
    32.79
    $
    36.02Light/medium oil per bbl (including hedges)
    $
    32.04
    $      
    29.18
    $
    28.24
    $
    26.61
    $
    29.09Heavy oil per bbl (before hedges)
    $
    31.63
    $      
    23.47
    $
    24.17
    $
    20.61
    $
    24.74Heavy oil per bbl (including hedges)
    $
    24.63
    $      
    21.92
    $
    22.16
    $
    20.25
    $
    22.09Natural gas liquids per barrel
    $
    45.13
    $      
    37.16
    $
    28.26
    $
    34.48
    $
    35.87Natural gas per mcf (before hedges)
    $
    7.94
    $        
    6.87
    $
    5.88
    $
    5.62
    $
    6.63Natural gas per mcf (including hedges)
    $
    6.49
    $        
    5.64
    $
    5.14
    $
    5.48
    $
    5.71(1) Redwater Midstream assets aquired September 30, 2003
PROVIDENT ENERGY TRUST |
    
67
68 | ANNUAL REPORT 2003
Quarterly Table
    
    
    
    
    
    2002First
    
    Second
    
    Third
    
    Fourth
    
    YTD($000s except per
    unit amounts)
    
    Quarter
    
    Quarter
    
    Quarter
    
    Quarter
    
    TotalFinancialRevenue
    $
    24,861
    $
    36,800
    $
    37,286
    $
    64,561
    $
    163,508Cash flow
    $
    15,324
    $
    22,642
    $
    22,631
    $
    36,299
    $
    96,896Net income - restated (1)
    $
    823
    $
    763
    $
    (279)
    $
    7,033
    $
    8,340Unitholder distributions
    $
    14,813
    $
    17,794
    $
    18,839
    $
    30,080
    $
    81,526Distributions per unit
    $
    0.46
    $
    0.49
    $
    0.51
    $
    0.57
    $
    2.03OperatingProductionLight/medium oil (bpd)
    
    3,147
    
    5,025
    
    4,691
    
    7,478
    
    5,096Heavy oil (bpd)
    
    5,712
    
    6,019
    
    7,032
    
    6,459
    
    6,310Natural gas liquids (bpd)
    
    850
    
    800
    
    903
    
    1,558
    
    1,030Natural gas (mcfd)
    
    36,111
    
    48,648
    
    47,728
    
    91,766
    
    56,193Oil
    equivalent (boed)
    
    15,728
    
    19,952
    
    20,581
    
    30,789
    
    21,801Average selling price (Cdn $)Light/medium oil per bbl (before hedges)
    $
    28.88
    $
    35.14
    $
    37.41
    $
    35.65
    $
    34.90Light/medium oil per bbl (including hedges)
    $
    28.88
    $
    34.91
    $
    37.07
    $
    35.26
    $
    34.62Heavy oil per bbl (before hedges)
    $
    21.1
    $
    27.9
    $
    29.35
    $
    22.73
    $
    25.46Heavy oil per bbl (including hedges)
    $
    19.84
    $
    20.15
    $
    21.31
    $
    18.66
    $
    20.02Natural gas liquids per barrel
    $
    21.17
    $
    27.01
    $
    29.78
    $
    33.82
    $
    29.04Natural gas per mcf (before hedges)
    $
    3.52
    $
    4.2
    $
    3.44
    $
    5.21
    $
    4.35Natural gas per mcf (including hedges)
    $
    4.35
    $
    4.52
    $
    4.29
    $
    5.06
    $
    4.67(1)
    Restated for the change in accounting policy for asset retirement
    obligations described in Note 3 to the consolidated financial statements.
  68 | PROVIDENT ENERGY TRUSTANNUAL REPORT 2003 | 69
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 judgements and estimates. Financial information in the
Annual Report is consistent with that presented in the financial statements.
Management maintains a system of internal controls to provide reasonable
assurance that all of the Trust's assets are
safeguarded and to facilitate the preparation of relevant, accurate and
timely information.
PricewaterhouseCoopers LLP, Chartered Accountants, appointed
by the unitholders, have audited the financial statements and conducted a review
of internal accounting policies and procedures to the extent required by
generally accepted auditing standards, and performed such tests as they deemed
necessary to enable them to express an opinion on the financial statements.
The Board of Directors, through its Audit Committee, is
responsible for ensuring that management fulfills its responsibility for
financial reporting and internal control. The Audit Committee is composed of
three independent directors. The Audit Committee reviews the financial content
of the Annual Report and reports its findings to the Board of Directors for its
consideration in approving the financial statements.
(signed)
    
    (signed)Thomas W. Buchanan
    
    Mark N. WalkerChief Executive
    Officer
    
    Chief Financial
    OfficerCalgary,
    AlbertaMarch 11, 2004
PROVIDENT ENERGY TRUST |
    69
70 | ANNUAL REPORT 2003To the Unitholders of Provident Energy TrustWe have audited the consolidated balance sheets of Provident
Energy Trust as at December 31, 2003 and 2002, and the consolidated statements
of operations and accumulated loss and cash flows for the years ended December
31, 2003 and 2002. These financial statements are the responsibility of the
management of Provident. Our responsibility is to express an opinion on these
financial statements based on our audits.
We conducted our audits in accordance with Canadian generally
accepted auditing standards. Those standards require that we plan and perform an
audit to obtain reasonable assurance whether the financial statements are free
of material misstatement. An audit includes examining, on a test basis, evidence
supporting the amounts and disclosures in the financial statements. An audit
also includes assessing the accounting principles used and significant estimates
made by management, as well as evaluating the overall financial statement
presentation.
In our opinion, these consolidated financial statements
present fairly, in all material respects, the financial position of the Trust as
at December 31, 2003 and 2002, and the results of its operations and cash flows
for the years ended December 31, 2003 and 2002 in accordance with Canadian
generally accepted accounting principles.
(signed)PricewaterhouseCoopers LLP
    
    Calgary,
    AlbertaChartered
    Accountants
    
    March 11, 2004Comments by Auditor for U.S. readers on Canada-U.S. reporting differencesIn the United States, reporting standards for auditors
require the addition of an explanatory paragraph (following the opinion
paragraph) when there is a change in accounting principles that has a material
effect on the comparability of the Company's financial statements, such as the
changes described in Note 3 to the Consolidated Financial Statements. Our report
to the shareholders dated March 11, 2004 is expressed in accordance with
Canadian reporting standards which do not require a reference to such a change
in accounting principles in the Auditors' report when the change is properly
accounted for and adequately disclosed in the financial statements.
(signed)PricewaterhouseCoopers LLP
    
    Calgary,
    AlbertaChartered
    Accountants
    
    March 11, 2004
  70 | PROVIDENT ENERGY TRUSTANNUAL REPORT 2003 | 71
Balance SheetAs
    at December 31,Canadian dollars
    (000s)
    
    2003
    
    2002(restated note 3)AssetsCurrent assetsCash
    $
    45
    $
    42Accounts receivable
    
    118,890
    
    47,463Petroleum product inventory
    
    24,206
    
    -Assets held for sale
    
    -
    
    1,145Prepaids
    
    5,632
    
    2,605148,773
    
    51,255Cash reserve for future site reclamation (Note 18)
    
    1,829
    
    1,490Goodwill (Note 4)
    
    102,443
    
    102,443Property, plant and
    equipment (Note 7)
    
    884,891
    
    719,859$
    1,137,936
    $
    875,047LiabilitiesCurrent liabilitiesAccounts payable and accrued liabilities
    $
    121,832
    $
    54,783Cash distributions payable
    
    8,389
    
    8,153Payable to the Manager (Note 14)
    
    -
    
    4,000130,221
    
    66,936Long-term debt (Note 8)
    
    236,500
    
    187,200Asset retirement obligation (Notes 3 and 9)
    
    33,182
    
    32,645Future income taxes (Note 15)
    
    58,805
    
    116,846Unitholders' EquityUnitholders' contributions (Note 10)
    
    803,299
    
    513,835Exchangeable shares (Note 10)
    
    19,518
    
    57,036Convertible debentures (Note 11)
    
    119,395
    
    61,279Contributed surplus (Note 13)
    
    1,305
    
    -Accumulated loss
    
    (4,029)
    
    (37,423)Accumulated cash distributions (Note 6)
    
    (248,018)
    
    (118,406)Accumulated
    interest on convertible debentures
    
    (12,242)
    
    (4,901)679,228
    
    471,420$
    1,137,936
    $
    875,047
PROVIDENT ENERGY TRUST |
    
    
    
    71
72 | ANNUAL REPORT 2003
Operations and Accumulated LossFor
    the year ended December 31,Canadian dollars
    (000s except per unit amounts)
    
    2003
    
    2002(restated note 3)RevenueSales
    $
    473,571
    $
    207,823Royalties
    
    (72,869)
    
    (44,315)400,702
    
    163,508ExpensesCost of goods sold
    
    153,147
    
    -Production, operating and maintenance
    
    84,040
    
    52,741General and administrative (Note 12)
    
    16,670
    
    7,987Management fees (Notes 12 and 14)
    
    -
    
    11,296Management internalization (Note 14)
    
    18,592
    
    -Interest on long-term debt
    
    9,733
    
    5,307Depletion, depreciation and accretion
    
    138,272
    
    92,987420,454
    
    170,318Loss before taxes
    
    (19,752)
    
    (6,810)Capital taxes
    
    3,332
    
    3,264Future income tax
    recovery (Note 15)
    
    (56,478)
    
    (18,414)(53,146)
    
    (15,150)Net income for the year
    
    33,394
    
    8,340Accumulated loss, beginning of year
    
    (36,064)
    
    (45,996)Retroactive application of changes in accounting policies (Note 3)
    
    (1,359)
    
    233Accumulated loss,
    beginning of year restated
    
    (37,423)
    
    (45,763)Accumulated loss,
    end of year
    $
    (4,029)
    $
    (37,423)Net income per unit
    - basic
    $
    0.38
    $
    0.09- diluted
    $
    0.38
    $
    0.09The accompanying notes form an integral part of these
consolidated financial statements.
  72 | PROVIDENT ENERGY TRUSTANNUAL REPORT 2003 | 73
Cash FlowsFor
    the year ended December 31,Canadian dollars
    (000s)
    
    2003
    
    2002(restated note 3)Cash provided by operating activitiesNet income for the year
    $
    33,394
    $
    8,340Add non-cash items:Depletion, depreciation and accretion
    
    138,272
    
    92,987Amortization of deferred charges
    
    621
    
    8,983Non-cash general and administrative (Note 12)
    
    1,305
    
    -Future income tax recovery
    
    (56,478)
    
    (18,414)Management internalization (Note 14)
    
    18,592
    
    -Management fee paid with trust units (Note 14)
    
    -
    
    5,000Cash flow from operations
    
    135,706
    
    96,896Change
    in non-cash working capital
    
    (23,377)
    
    (7,090)112,329
    
    89,806Cash provided by financing activitiesIncrease (decrease) in long-term debt
    
    49,300
    
    (10,325)Declared distributions to unitholders
    
    (129,612)
    
    (81,526)Issue of trust units, net of issue costs
    
    220,262
    
    56,014Issue of debentures, net of costs
    
    71,800
    
    61,398Interest on convertible debentures
    
    (7,341)
    
    (4,901)Change
    in non-cash financing working capital
    
    28
    
    3,949204,437
    
    24,609Cash used in investing activitiesExpenditures on property, plant and equipment
    
    (31,628)
    
    (21,980)Acquisition of Redwater (Note 4)
    
    (298,638)
    
    -Acquisition of Provident Management Corp (Note 14)
    
    (364)
    
    -Acquisition of Richland Energy Corporation (Note 4)
    
    -
    
    (3,389)Acquisition of Meota Resources Corp. (Note 4)
    
    -
    
    (32,141)Acquisition of oil and natural gas properties
    
    -
    
    (70,936)Proceeds on disposition of oil and natural gas properties
    
    9,947
    
    11,157Reclamation fund contributions
    
    (2,492)
    
    (1,317)Reimbursement for leasehold improvements
    
    1,437
    
    -Change
    in non-cash investing working capital
    
    4,975
    
    4,198(316,763)
    
    (114,408)Increase in cash
    
    3
    
    7Cash beginning
    of year
    
    42
    
    35Cash end of year
    $
    45
    $
    42Supplemental disclosure of cash flow informationCash interest paid including debenture interest
    $
    17,876
    $
    4,713Cash
    capital taxes paid
    $
    4,077
    $
    3,264
The accompanying notes form an integral part of these
consolidated financial statements.
PROVIDENT ENERGY TRUST |
    
7374 | ANNUAL REPORT 2003(Tabular amounts in Cdn$ 000s, except unit and per unit
amounts)
December 31, 2003
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, interests in petroleum and natural gas
  properties and commenced operations March 6, 2001.
  Cash flow is provided to the Trust from the properties
  owned and operated by Provident Energy Ltd. and directly and indirectly owned
  subsidiaries and partnerships of the Trust ("Provident"). Cash flow is paid
  from Provident to the Trust by way of royalty payments, interest payments and
  principal repayments. The cash payments received by the Trust are subsequently
  distributed to the unitholders monthly.
2.
Significant accounting policies
(a) Basis of presentation
These consolidated financial statements include the accounts of the Trust
    and Provident.
(b) Property, plant and equipmentThe Trust follows the full cost method of accounting for
    oil and natural gas exploration and development activities, whereby all
    costs associated with the acquisition and development of oil and natural gas
    reserves are capitalized. Such costs include lease acquisition, lease
    rentals on non-producing properties, geological and geophysical activities,
    drilling of productive and non-productive wells, and tangible well
    equipment. Gains or losses on the disposition of oil and gas properties are
    not recognized unless the resulting change to the depletion and depreciation
    rate is 20 percent or more. General and administrative costs are not
    capitalized other than to the extent that they are directly related to a
    successful acquisition.
    All other property, plant and equipment, including midstream assets, are
    recorded at cost.
    Inventories used to fill in cavern bottoms are presented as part of
    property, plant and equipment and stated at historical cost. These
    inventories are not depreciated.
    Depletion, depreciation and accretion
The provision for depletion and depreciation for oil and
    natural gas assets is calculated 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 six thousand 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 unimpaired cost of unproved properties.
74 | PROVIDENT ENERGY TRUSTANNUAL REPORT 2003 | 75
Midstream facilities, including natural gas storage
    facilities and natural gas liquids extraction facilities are carried at cost
    and depreciated on a straight-line basis over the estimated service lives of
    the assets which are predominantly 30 years. Capital assets related to
    pipelines are carried at cost and depreciated using the straight-line method
    over their economic lives.
    Ceiling testThe ceiling test limits the carrying value of oil and
    natural gas properties, net of future income taxes and asset retirement
    obligation, to the estimated undiscounted future net production revenue
    associated with the proved oil and natural gas reserves, plus the unimpaired
    costs of unproved properties, less estimated future general and
    administrative expenses, interest and income taxes. The test uses costs and
    prices in effect at the balance sheet date. In the application of the
    ceiling test, any excess carrying value of the assets on the balance sheet
    is charged to income in the current period.
(c) InventoryInventories of products are valued at the lower of average cost and net
    realizable value.
(d) GoodwillGoodwill, which represents the excess of purchase price over fair value
    of net assets received, 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.
(e) Asset retirement obligationProvident follows the new Canadian Institute of Chartered Accountants
    standard for Asset Retirement Obligation ("ARO"). Under this 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.
(f) Unit option planUnder Provident's option plan the exercise price of the option may be
    reduced in future periods, based upon the cash distributions made on the
    trust units, at the discretion of the option holder. Therefore, it is not
    possible to determine a fair value for options granted using a traditional
    option pricing model. Provident accounts for the unit option plan using the
    intrinsic value of the option, for unexercised options at the financial
    statement date. Compensation expense associated with the options is deferred
    and recognized in earnings over the vesting period of the options with a
    corresponding increase in contributed surplus. Any changes in the intrinsic
    value of unexercised options are recognized in earnings in the period of
    change with a corresponding increase or decrease to contributed surplus.
    Recoveries of compensation expense will only be recognized to the extent of
    previously recorded cumulative compensation expense associated with
    exercised and outstanding options as of the date of the financial
    statements. Consideration upon exercise of the options, along with the
    amount recorded as contributed surplus, is recorded as an increase in
    unitholders' contributions.
PROVIDENT ENERGY TRUST |
    
    
    
75
76 | ANNUAL REPORT 2003(g) Financial instrumentsProvident uses financial instruments and physical delivery commodity
    contracts from time to time to reduce its exposure to fluctuations in
    commodity prices, foreign exchange rates and interest rates. Gains and
    losses relating to these transactions are deferred and recognized in the
    financial statement category to which the hedge relates at the time the
    underlying commodity is sold or when the positions are settled.
(h) Future income taxesProvident 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 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 income taxes has
    been made in the Trust.
(i) Revenue recognitionRevenues associated with the sales of Provident's natural gas, natural
    gas liquids ("NGL's") and crude oil owned by Provident are recognized when
    title passes from Provident to its customer.
    Marketing revenues and purchased product are recorded on a gross basis as
    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 as the services are provided. Revenues
    associated with the sale of natural gas storage services are recognized when
    the services are provided.
(j) Use of estimates
The preparation of financial statements requires
    management to make estimates based on currently available information. In
    particular, estimates are made by management for amounts recorded for
    depletion and depreciation of the property, plant and equipment ("PP&E"),
    and asset retirement obligation. The ceiling test uses factors such as
    estimated proved reserves, production rates, petroleum and natural gas
    prices and future costs. Due to the inherent limitations in metering and the
    physical properties of storage caverns 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.
3.     
Changes in accounting policy
Asset retirement obligationThe Trust adopted CICA Handbook Section 3110 "Asset
  Retirement Obligations" effective December 2003. This change in accounting
  policy has been applied retroactively with restatement of prior periods
  presented for comparative purposes. Previously, the Trust recognized a
  provision for future site reclamation based on the unit-of-production method
  applied to estimated future site abandonment and reclamation costs.
  As a result of this change, net income for the year ended
  December 31, 2003 increased by $0.04 million ($0.06 million net of future
  income tax expense of $0.02 million). At December 31, 2003 the ARO balance
  increased by $0.5 million to $33.2 million, the net PP&E balance decreased by
  $4.3 million to $884.9 million and the future tax liability increased by $0.02
  million to $58.8 million.
76 | PROVIDENT ENERGY TRUST
ANNUAL REPORT 2003 | 77
The amounts previously reported for 2002 have been restated due to the
  retroactive application of the new ARO standard. As a result of this change,
  net income for the year ended December 31, 2002 decreased by $1.6 million
  ($2.5 million net of future income tax recovery of $0.9 million). At December
  31, 2002 the ARO balance increased by $19.9 million to $32.6 million, the net
  PP&E balance increased by $19.9 million to $719.9 million and the future tax
  liability increased by $0.9 million to $116.8 million.
  Opening 2003 accumulated loss increased by $1.4 million ($2.1 million net
  of future income tax recovery of $0.7) while the opening 2002 accumulated loss
  decreased by $0.2 million ($0.4 million net of future income tax expense of
  $0.2 million) to reflect the cumulative impact of additional depreciation,
  depletion and accretion expense net of the previously recorded provision for
  site restoration.
  Unit option plan
The Trust adopted CICA Handbook Section 3870 "Stock-based compensation and
  other stock-based payments" effective December 2003. This change in accounting
  policy has been applied prospectively.
  As a result of this change, net income for the year ended December 31, 2003
  decreased by $1.3 million. At December 31, 2003 contributed surplus increased
  to $1.3 million due to the implementation of the accounting policy.
4.     
Acquisitions
(a)On September 30, 2003,
  Provident acquired Western Canadian midstream assets ("Redwater") for $298.6
  million.
  The purchase price was financed through $35.8 million of long-term debt,
    $71.8 million of net proceeds from the issuance of convertible debentures,
    and $191.1 million in net proceeds from the issuance of 19,205,000 trust
    units.
    Provident allocated the purchase price of Redwater as follows:
Net assets
        acquiredPetroleum product inventory
        $
        15,413Property, plant
        and equipment (includes acquisition costs of $6,763)
        
        283,225$
        298,638The acquisition
        was financed by:Long-term debt (Note 8)
        
        35,768Issuance of trust units (net of costs $10,582)(Note 10)
        $
        191,070Issuance of
        convertible debentures (net of costs of $3,200)
        
        71,800$
        298,638
PROVIDENT ENERGY TRUST |
    
    
    
    77
78 | ANNUAL REPORT 2003(b) Meota Resources Corp. ("Meota")Effective October 1, 2002 Provident acquired Meota for cash
  consideration of $27.1 million and 14,517,184 trust units with an ascribed
  value of $158.3 million, plus 5,858,136 exchangeable shares with an ascribed
  value of $63.9 million. The transaction has been accounted for using the
  purchase method with the allocation of the purchase price as follows:
Net assets
      acquired and liabilities assumedProperty, plant and equipment
      $
      313,305Goodwill
      
      89,137Working capital deficiency, net of cash
      
      (2,816)Long-term debt
      
      (86,500)Site
      reclamation liability
      
      (1,084)Future income taxes
      
      (57,653)$
      254,389ConsiderationCash
      $
      27,134Acquisition costs incurred
      
      5,007Total cash consideration
      
      32,141Trust units issued
      
      158,336Exchangeable shares issued
      
      63,912$
      254,389(c) Richland Petroleum Corporation ("Richland")
Effective January 16, 2002 Provident acquired Richland for
  consideration of 11,157,225 Trust units with an ascribed value of $98.9
  million. The transaction has been accounted for using the purchase method with
  the allocation of the purchase price as follows:
Net
      assets acquired and liabilities assumedCash
      reserved for future site reclamation
      $
      372Goodwill
      
      
      13,306Fair
      market value of financial hedges and physical contracts for petroleum
      products
      
      10,133Property, plant
      and equipment
      
      
      219,151Working capital
      deficiency
      
      
      (10,744)Long-term debt
      
      
      (75,425)Site reclamation
      liability
      
      
      (1,559)Future income
      taxes
      
      
      (52,660)$
      102,574ConsiderationAcquisition costs incurred (includes $332 incurred in 2001)
      $
      3,721Trust units
      issued
      
      
      98,853$
      102,574

  78 | PROVIDENT ENERGY TRUSTANNUAL REPORT 2003 | 795.     
Segmented informationOil
      and
      MidstreamNatural
      
      Services
      
      Inter-Gas
      
      and
      segmentProduction
      Marketing
      Elimination
      
      TotalRevenueGross production revenue
      $
      299,904
      $
      -
      $
      -
      $
      299,904Royalties
      
      (72,869)
      
      -
      
      -
      
      (72,869)Product sales and services revenue
      
      -
      
      197,148
      
      (24,957)
      
      172,191Other revenue
      
      1,476
      
      -
      
      -
      
      1,476228,511
      
      197,148
      
      (24,957)
      
      400,702ExpensesCost
      of goods sold
      
      -
      
      178,104
      
      (24,957)
      
      153,147Production, operating and maintenance
      
      76,396
      
      7,644
      
      -
      
      84,040Cash
      general and administrative
      
      14,289
      
      1,076
      
      -
      
      15,365Non-cash general and administrative
      
      1,223
      
      82
      
      -
      
      1,305Management
      internalization
      
      18,592
      
      -
      
      -
      
      18,592110,500
      
      186,906
      
      (24,957)
      
      272,449Earnings before
      interest, taxes, depletion,depreciation and accretion
      
      118,011
      
      10,242
      
      -
      
      128,253Interest on
      long-term debt
      
      8,568
      
      1,165
      
      -
      
      9,733Depletion,
      depreciation and accretion
      
      136,066
      
      2,206
      
      -
      
      138,272Capital taxes
      
      3,177
      
      155
      
      -
      
      3,332Future income tax recovery (Note
      15)
      
      (55,074)
      
      (1,404)
      
      -
      
      (56,478)92,737
      
      2,122
      
      -
      
      94,859Net income for the year
      $
      25,274
      $
      8,120
      $
      -
      $
      33,394Capital
      expendituresAcquisition of Redwater
      $
      -
      $
      298,638
      $
      -
      $
      298,638Property, plant and equipment
      
      31,628
      
      -
      
      -
      
      31,628Selected
      balance sheet itemsWorking capitalAccounts receivable
      
      47,691
      
      76,106
      
      (4,907)
      
      118,890Petroleum product inventory
      
      -
      
      24,206
      
      -
      
      24,206Accounts payable
      
      52,146
      
      74,593
      
      (4,907)
      
      121,832Long-term debt
      
      136,500
      
      100,000
      
      -
      
      236,500
  Provident's business activities are conducted through two business
  segments; oil and natural gas production and midstream services and marketing.
  Oil and natural gas production includes exploitation,
  development and production of crude oil and natural gas reserves. Midstream
  services and marketing includes fractionation, transportation, loading and
  storage of natural gas liquids, and marketing of crude oil and natural gas
  liquids.
  In 2002 Provident operated in only one business segment, oil and natural
  gas production. Therefore, no segmented comparatives have been presented.
PROVIDENT ENERGY TRUST |
    79
80 | ANNUAL REPORT 20036.     
Reconciliation of cash flow and distributionsFor the year ended December 31,2003
      
      2002Cash flow from
      operations
      $
      135,706
      $
      96,896Cash reserved for
      interest on convertible debentures
      
      (7,341)
      
      (4,901)Cash (reserved) used for
      financing and investing activities
      
      1,247
      
      (10,469)Cash
      distributions to unitholders
      
      129,612
      
      81,526Accumulated cash distributions,
      beginning of year
      
      118,406
      
      36,880Accumulated cash distributions,
      end of year
      $
      248,018
      $
      118,406Cash distributions per unit
      $
      2.06
      $
      2.037.     
Property, plant and equipment
Accumulateddepletion and
      Net
      BookDecember 31, 2003
      Cost
      depreciation
      valueOil and natural
      gas properties
      $       
      990,568
      $
      391,922
      $
      598,646Midstream assets
      283,225
      
      2,206
      281,019Office equipment
      8,359
      
      3,133
      5,226Total
      $    
      1,282,152
      $
      397,261
      $ 884,891
  Accumulateddepletion and
      Net BookDecember 31, 2002 (restated -
      note 3)
      Cost
      depreciation
      
      valueOil and natural
      gas properties
      $
      973,598
      $
      255,901
      $
      717,697Office equipment
      4,042
      
      1,880
      
      2,162Total
      $ 977,640
      $
      257,781
      $
      719,859
Costs associated with unproved properties excluded from costs subject to
  depletion as at December 31, 2003 totaled $16.4 million (December 31, 2002 -
  $30.2 million).
8.    
Long-term debt
December 31,2003
      
      2002Revolving term credit facility
      $     
      236,500
      $
      187,200
  Provident has a $335 million term credit facility with a
  syndicate of Canadian chartered banks. Interest rates under the terms of the
  credit facility are determined quarterly based on the ratio of quarter end
  debt divided by the previous quarter's cash flow annualized. At December 31,
  2003, the rate was bank prime of 4.5 percent plus 0.5 percent. In February
  2004 Provident executed a credit agreement consent and amendment that
  restricted the borrowing base under this facility to $310 million.
  Pursuant to the terms of the agreement, each year on or
  after May 24 Provident can request the revolving period be extended for a
  further 364 day period. If the lenders do not extend the revolving period, at
  Provident's option the credit facility is converted to a one year
  non-revolving term credit facility at the end of the 364 day term, with
  one-sixth of
80 | PROVIDENT ENERGY TRUST
ANNUAL REPORT 2003 | 81
the loan balance due May 2005, one-twelfth due August 2005
  and the remaining balance due at the end of the term period. As collateral
  security, Provident has pledged a $500 million fixed and floating charge
  debenture against all of its assets.
  At December 31, 2003 Provident had letters of credit
  guaranteeing Provident's performance under certain commercial contracts that
  totaled $12.3 million, marginally increasing bank line utilization to 80
  percent of the restricted borrowing base. The guarantees are associated with
  the marketing segment of the midstream business unit. At December 31, 2002
  Provident's guarantees were negligible.
  9.     Asset retirement obligation
Provident's asset retirement obligation is based on the
  Trust's net ownership in wells and facilities and management's estimate of the
  costs to abandon and reclaim those wells and facilities as well as an estimate
  of the future timing of the costs to be incurred. Midstream assets, including
  the Redwater facility, the Younger Plant and the liquids gathering system have
  been excluded from the asset retirement obligation as retirement obligations
  associated with these assets have indeterminate settlement dates.
  The total undiscounted amount of future cash flows required
  to settle asset retirement obligations is estimated to be $99.7 million.
  Provident has estimated the present value of the asset retirement obligation
  to be $33.2 million as at December 31, 2003. Payments to settle asset
  retirement obligations occur over the operating lives of the assets estimated
  to be from zero to 20 years. Estimated cash flows have been discounted at
  Provident's credit-adjusted risk free rate of 7 percent and an inflation rate
  of 2 percent.
For the year ended December 31,2003
      
      2002(restatednote
      3)Carrying amount,
      beginning of year
      $
      32,645
      $
      12,740Increase in
      liabilities during the year
      
      519
      
      18,775Settlement of
      liabilities during the year (Note 18)
      
      (2,153)
      
      (600)Accretion expense
      
      2,171
      
      1,730Carrying amount, end of year
      $
      33,182
      $
      32,64510.    Unitholders' contributions and exchangeable sharesThe Trust has authorized capital of an unlimited number of common voting
  trust units.
  During 2003 the Trust issued 19,205,000 units (16,700,000
  on September 30, 2003 and 2,505,000 on exercise of underwriters options) for
  gross proceeds of $201.7 million, in a financing concurrent with the purchase
  of the Redwater assets (Note 4).
  On January 17, 2003 Provident Energy Ltd., a subsidiary,
  issued 1.7 million exchangeable shares as consideration for the acquisition of
  Provident Management Corp. (see Note 14). The conversion ratio for the
  exchangeable shares for the period January 17 to February 14, 2003 was equal
  to one trust unit for one exchangeable share, and is increased on each date a
  distribution is paid by the trust. The exchangeable shares are held in escrow
  and are releasable as to 25 percent per year beginning on June 30, 2003, and
  are releasable or may be forfeited in certain other limited circumstances.
  On January 16, 2002 the Trust issued 11.2 million trust units as
  consideration for the Richland acquisition. On October 1, 2002, the Trust
  issued 14.5 million trust units and Provident Acquisitions Inc., a subsidiary,
  issued 5.9 million exchangeable
PROVIDENT ENERGY TRUST |
    
    
    
81
82 | ANNUAL REPORT 2003
shares as partial consideration for the acquisition of
  Meota Resources Corp. The conversion ratio for the exchangeable shares for the
  period October 1 to November 14, 2002 was equal to one trust unit for one
  exchangeable share, and is increased on each date a distribution is paid by
  the Trust between October 1, 2002 and the date the exchangeable share is
  converted, at the option of the holder, into trust units. On January 15, 2005,
  all remaining exchangeable shares will be automatically exchanged for trust
  units, subject to extension at the option of the Trust.
  Effective with the May, 2002 distribution, the Trust
  initiated a premium distribution, distribution reinvestment plan ("DRIP"). The
  DRIP permits eligible unitholders to direct their distributions to the
  purchase of additional units at 95 percent of the average market price as
  defined in the plan ("Regular DRIP"). The premium distribution component
  permits eligible unitholders to elect to receive 102 percent of the cash the
  unitholder would otherwise have received on the distribution date ("Premium
  DRIP"). Participation in the Regular and Premium DRIP is subject to proration
  by the Trust. Unitholders who participate in either the Regular DRIP or the
  Premium DRIP are also eligible to participate in the optional unit purchase
  plan as defined in the DRIP.
Trust
      units
      Year ended December 31,2003
      
      
      2002Number
      
      Amount
      Number
      
      Amountof Units
      
      (000s)
      of Units
      
      (000s)Balance at
      beginning of year
      53,729,335
      $
      513,835
      21,054,119
      $
      187,587Issued for cash
      19,205,000
      
      201,653
      -
      
      -Exchangeable
      share conversions
      5,726,525
      
      55,518
      644,150
      
      6,876Issued pursuant
      to unit option plan
      202,446
      
      1,626
      126,034
      
      1,103Issued pursuant
      to the distribution reinvestment plan
      2,478,956
      
      25,880
      1,751,652
      
      17,744To be issued
      pursuant to the distribution reinvestment plan
      141,361
      
      1,528
      -
      
      -Debenture
      conversions
      1,341,065
      
      14,350
      11,681
      
      125Issued from
      Treasury
      -
      
      -
      3,900,000
      
      39,390Issued for
      corporate acquisitions
      -
      
      -
      25,674,409
      
      257,189Issued for
      property acquisition
      -
      
      -
      100,000
      
      1,050Issued to
      Provident Management Corporation
      -
      
      -
      467,290
      
      5,000Unit issue costs
      -
      
      (11,091)
      -
      
      (2,229)Balance at end of year
      82,824,688
      $
      803,299
      53,729,335
      $
      513,835
  Exchangeable shares
      Year ended December 31,2003
      
      
      2002Number
      
      Amount
      Number
      Amountof Shares
      
      (000s)
      of Shares
      
      (000s)Provident
      Acquisitions Inc.Balance at
      beginning of year
      5,227,844
      $
      57,036
      -
      $
      -Issued to acquire
      Meota Resources Corp.
      -
      
      -
      5,858,136
      
      63,912Converted to
      trust units
      (4,693,487)
      
      (51,207)
      (630,292)
      
      (6,876)Balance, end of
      year
      534,357
      
      5,829
      5,227,844
      
      57,036Exchange ratio, end of year
      1.2517
      
      -
      1.03597
      
      -Trust units issuable upon
      conversion, end of year
      668,855
      
      5,829
      5,415,890
      $
      57,036
  82 | PROVIDENT ENERGY TRUSTANNUAL REPORT 2003 | 83
Exchangeable sharesNumber
      
      Amountof Shares
      
      (000s)Provident
      Energy Ltd.Balance, December
      31, 2002
      -
      $
      -Issued to acquire
      Provident Management Corp.
      1,682,242
      
      18,000Converted to
      trust units
      (403,015)
      
      (4,311)Balance, end of
      year
      1,279,227
      
      13,689Exchange ratio,
      end of year
      1.18663
      
      -Trust units issuable upon
      conversion, end of year
      1,517,969
      $
      13,689
The per trust unit amounts for 2003 were calculated based
  on the weighted average number of units outstanding of 68,448,203, which
  includes the shares exchangeable into trust units. The per trust unit amounts
  for 2002 were calculated based on the weighted average number of units
  outstanding of 40,221,914. Net income available for distribution to
  unitholders in the basic per trust unit calculations has been reduced by
  interest on the convertible debentures. The diluted per trust unit amounts are
  calculated including an additional 50,098 trust units (2002 - 56,510) for the
  dilutive effect of the unit option plan. Provident's convertible debentures
  are not included in the computation of diluted earning per unit as their
  effect is anti-dilutive.
11.    Convertible debenturesOn September 30, 2003 the Trust issued $75 million of unsecured
  subordinated convertible debentures ($71.8 million net of issues costs) with a
  8.75 percent coupon rate maturing December 31, 2008. The debentures may be
  converted into trust units at the option of the holder at a conversion price
  of $11.05 per trust unit prior to December 31, 2008, and may be redeemed by
  the Trust under certain circumstances.
  On April 11, 2002 the Trust issued $64.4 million of
  unsecured subordinated convertible debentures ($61.4 million net of issue
  costs) with a 10.5 percent coupon rate maturing May 15, 2007. The debentures
  may be converted into trust units at the option of the holder at a conversion
  price of $10.70 per trust unit prior to May 15, 2007, and may be redeemed by
  the Trust under certain circumstances.
  The debentures and related interest obligations have been
  classified as equity on the consolidated balance sheet as the Trust may elect
  to satisfy interest and principle obligations by the issuance of trust units.
  During the year $14.35 million of 10.5 percent debentures were converted to
  trust units.
12.    General and administrative expenses
Year ended December 31,2003
      
      2002General &
      administrative expenses
      $
      15,365
      $
      7,987Non-cash general
      and administrative expenses (1)
      
      1,305
      
      -Management fee
      
      -
      
      11,296Total cash, non-cash general and
      administrative expenses and management fee
      $
      16,670
      $
      19,283
(1) non-cash general and administrative expenses is made up entirely by the
  trust unit incentive compensation expense.
PROVIDENT ENERGY TRUST |
    
    
    
    83
84 | ANNUAL REPORT 200313.    Unit option planYear ended December 31,2003
      
      
      2002Weighted
      
      WeightedNumber
      Average
      Number
      
      Averageof Options
      Exercise
      of Options
      
      ExerciseOutstanding,
      beginning of year
      796,810
      $
      10.86
      611,100
      $
      11.16Granted
      3,443,550
      
      11.09
      345,013
      
      10.32Exercised
      (202,446)
      
      10.62
      (126,034)
      
      10.87Cancelled
      (29,170)
      
      11.18
      (33,269)
      
      10.72Outstanding, end of year
      4,008,744
      
      11.06
      796,810
      
      10.86Exercisable at end of year
      1,535,004
      $
      11.07
      330,149
      $
      11.09
The Trust Option Plan (the "Plan") is administered by the
  Board of Directors of Provident. Under the Plan, all directors, officers,
  employees and certain consultants of Provident are eligible to participate in
  the Plan. There are 5,000,000 trust units reserved for the Trust Option Plan.
  Options are granted at a "strike price" which is not less than the closing
  price of the units on The Toronto Stock Exchange on the last trading day
  preceding the grant. In certain circumstances, based upon the cash
  distributions made on the trust units, the strike price may be reduced at the
  time of exercise of the option at the discretion of the option holder. Options
  vest in the following manner; one-third vest six months after the grant date,
  one-third vest 1.5 years after the grant date and one-third vest 2.5 years
  after the grant date.
  At December 31, 2003, the Trust had 4,008,744 options
  outstanding with exercise prices ranging between $8.40 to $12.39 per unit. The
  weighted average remaining contractual life of the options is 3.09 years and
  the weighted average exercise price is $11.07 per unit excluding average
  potential reductions to the strike prices of $1.26 per unit.
  At December 31, 2002, the Trust had 796,810 options
  outstanding with prices ranging from $8.40 to $12.39 per unit. The weighted
  average exercise price was $11.09 per unit. The weighted average remaining
  contractual life of the options was 2.8 years.
  Provident recorded compensation expense and contributed
  surplus, based on the year end unit price, of $1.3 million for the 3.4 million
  options granted on or after January 1, 2003. Provident has elected to apply
  the provision of CICA section 3870 prospectively, therefore, no compensation
  expense is associated with options granted prior to January 1, 2003.
14.    Related party transactions
Until January 17, 2003 the Trust was actively managed by Provident
  Management Corporation (the "Manager"), and in accordance with the terms of
  the management agreement, the Manager was entitled to receive a base fee in
  the amount of 2 percent of the operating cash flow of Provident, plus a total
  return fee based on distributions and unit price performance during the
  period. Pursuant to the management fee amending agreement approved in
  conjunction with the management internalization transaction (Note 10), the
  base fee paid for the period January 1 to October 31, 2002 was $1.8 million
  and $0.5 million for the period November 1 to December 31, 2002, for a total
  base fee of $2.3 million. The total return fee for 2002 was restricted to $9.0
  million, payable by way of $4.0 million in cash and 467,290 trust units valued
  at $5.0 million. The Manager was reimbursed for administration expenses which
  totaled $264,242 in 2002.
84 | PROVIDENT ENERGY TRUSTANNUAL REPORT 2003 | 85
On January 17, 2003, Provident acquired all the issued and outstanding
  shares of Provident Management Corporation, Manager of the Trust and
  Provident, for consideration of $18.0 million payable with the issuance of
  1,682,242 exchangeable shares. The exchangeable shares are held in escrow and
  are releasable as to 25 percent per year beginning on June 30, 2003, and are
  releasable or may be forfeited in certain other limited circumstances. This
  management internalization transaction eliminates external management fees
  effective January 1, 2003. The share purchase agreement as a condition of
  closing provides for executive employment contracts for the former
  shareholders of Provident Management Corporation.
  The full cost of this transaction, $18.6 million including transaction
  costs of $0.6 million, was expensed in 2003.
15.    Future income taxesThe difference between the accounting value and the income tax value of
  assets and liabilities, which comprise the future tax liability, are as
  follows:
December 31,2003
      
      2002(restated)Petroleum and natural gas properties and other
      $
      49,273
      $
      102,122Production facilities
      
      8,128
      
      14,724Midstream facilities
      
      1,404
      
      -$
      58,805
      $
      116,846
  The future income tax provision differs from the expected amount calculated
  by applying the Canadian combined federal and provincial income tax rate of
  40.6 percent (2002 - 42.1 percent) as follows:
Year ended December 31,2003
      
      2002(restated)Expected income
      tax recovery
      $
      (8,019)
      $
      (2,860)Increase
      (decrease) resulting from:Non-deductible
      Crown charges and other payments
      
      14,226
      
      12,728Federal resource
      allowance
      
      (8,563)
      
      (7,382)Alberta Royalty
      Tax Credit
      
      (183)
      
      (260)Payments to the
      Trust
      
      (33,454)
      
      (16,808)Income less
      related depletion and depreciation in awholly owned
      partnership and in the Trust
      
      382
      
      (2,630)Federal income tax rate changes
      and other
      
      (20,867)
      
      (1,202)$
      (56,478)
      $
      (18,414)16.    CommitmentsUnder the terms of the Redwater purchase and sale agreement
  Provident is committed to assumption or cancellation of financial assurances
  that the vendor had with suppliers. These financial assurances, which
  guarantee performance under certain commercial contracts, total $14.0 million.
PROVIDENT ENERGY TRUST |
    
    
    
85
86 | ANNUAL REPORT 2003
Provident has office lease commitments that extend through April 2013.
  Future minimum lease payments for the following five years are: 2004 - $2.3
  million; 2005 - $2.3 million; 2006 - $2.4 million, 2007 - $2.5 million; and
  2008 -$2.5 million.
17.    Financial instruments and hedgingProvident's commodity price risk management program is
  intended to minimize the volatility of Provident's commodity prices and to
  assist with stabilizing cash flow and distributions. Provident seeks to
  accomplish this through the use of financial instruments and physical delivery
  commodity contracts from time to time to reduce its exposure to fluctuations
  in commodity prices and foreign exchange rates. Gains and losses relating to
  these transactions are deferred and recognized in the financial statement
  category to which the hedge relates at the time the underlying commodity is
  sold or when the positions are settled.
  The carrying amounts of current assets, the reclamation
  fund, current liabilities and long-term debt as stated in the financial
  statements approximate their estimated fair value. Substantially all of the
  Trust's accounts receivable are with oil and gas marketers and joint venture
  partners in the oil and natural gas industry and are subject to normal
  industry credit risks.
  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.
(a) Commodity price
  (i) Crude oil
For 2003, Provident paid out $23.9 million to settle
    various oil market based contracts on an aggregate volume of 1,867,500
    barrels. For 2002, Provident paid out $13.0 million to settle various oil
    market based contracts on an aggregate volume of 2,286,250 barrels. The
    estimated value of contracts in place if settled at market prices at
    December 31, 2003 would have resulted in an opportunity cost of $21.1
    million (December 31, 2002 -$13.3 million). The contracts in place at
    December 31, 2003 are summarized in the following table:
Year
        Product
        Volume
        Terms
        Effective Period2004
        Light Oil
        4,500 Bpd
        WTI US$23.41
        per bbl
        January 1 -
        December 31500 Bpd
        WTI US$25.08
        per bbl
        January 1 -
        March 312005
        Light Oil
        2,000 Bpd
        WTI US$25.01
        per bbl
        January 1 -
        December 312004
        Heavy Oil (1)
        2,800 Bpd
        US$17.96 per
        bblat Hardisty
        January 1 - December 31
(1)The heavy oil price of US$17.96 per bbl has been fixed through a
    combination of US dollar denominated WTI contracts combined with US dollar
    differential contracts.
(ii) Natural gasFor 2003, Provident paid $25.0 million to settle various
    natural gas market based contracts on an aggregate of 23,063,900 gigajoules
    ("GJ"). For 2002, Provident received $6.6 million to settle various natural
    gas market based contracts on an aggregate of 11,554,250 gigajoules ("GJ").
    As at December 31, 2003 the estimated value of contracts in place settled at
    market prices at December 31 would have resulted in an opportunity cost of
    $4.1 million (December 31, 2002 -of $12.4 million). The contracts in place
    at December 31, 2003 are summarized in the following table:
86 | PROVIDENT ENERGY TRUST
ANNUAL REPORT 2003 | 87
Year
    Product
    Volume
    Terms
    Effective Period2004
    Natural Gas (2)
    5,000 Gjpd
    Cdn$4.95 per gj
    January 1 -
    December 319,000 Gjpd
    Cdn$6.36 per gj
    January 1 - March
    31900 Gjpd
    Cdn$5.75 per gj
    January 1 - October
    3127,000 Gjpd
    Cdn$5.10 per gj
    April 1 - October
    313,600 Gjpd
    Cdn$5.82 per gj
    November 1 -
    December 3110,000 Gjpd
    Funded CollarCdn$5.50 - $8.75
    per gj
    January 1 - March
    3110,000 Gjpd
    Costless collarCdn$5.50 - $7.85
    per gj
    January 1 - March
    315,000 Gjpd
    Costless collarCdn$6.00 - $7.28
    per gj
    January 1 - March
    315,000 Gjpd
    Costless collarCdn$6.25 - $8.00
    per gj
    January 1 - March
    313,000 Gjpd
    Costless collarCdn$5.50 - $6.23
    per gj
    April 1 - December
    313,000 Gjpd
    Costless collarCdn$5.25 - $7.10
    per gj
    November 1 -
    December 312,000 Gjpd
    Costless collarCdn$5.50 - $7.29
    per gj
    November 1 -
    December 312005
    Natural Gas (2)
    3,000 Gjpd
    Cdn$5.90 per gj
    January 1 - March
    31600 Gjpd
    Cdn$5.39 per gj
    January 1 - October
    313,000 Gjpd
    Costless collarCdn$5.25 - $7.10
    per gj
    January 1 - March
    312,000 Gjpd
    Costless collarCdn$5.50 - $7.29 per gj
    January 1 - March 31
(2)Natural gas contracts are settled against AECO monthly index.
(b) Foreign exchange contractsProvident had two foreign exchange sell contracts in place in 2003 for a
    total of US$1.25 million per month at an average exchange rate of Cdn$1.56
    per US$1.
18.    Cash reserve for future site reclamationProvident established a cash reserve effective May 1, 2001
  for future site reclamation expenditures. In accordance with the royalty
  agreement, Provident funds the reserve by paying $0.25 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. For the
  year ended December 31, 2003, $2.5 million was contributed to the reserve and
  actual expenditures totaled $2.2 million. For the year ended December 31,
  2002, $1.3 million was added to the cash reserve and actual expenditures
  totaled $0.6 million.
19.    Subsequent eventOn February 4, 2004 the Trust issued 4,500,000 Trust units at $11.20 per
  unit for proceeds of $50.4 million ($47.9 million net of issue costs) pursuant
  to a public offering prospectus dated January 22, 2004.
20.    Comparative balancesCertain comparative numbers have been restated to conform with the current
  year presentation.
PROVIDENT ENERGY TRUST | 87
88 | ANNUAL REPORT 200321.    Reconciliation of financial statements to United States
generally accepted accounting principlesThe consolidated financial statements have been prepared in accordance with
  accounting principles generally accepted in Canada ("Canadian GAAP"). Any
  differences in accounting principles 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. The
  application of US GAAP would have the following effects on net income as
  reported:
Year endedDecember 31,(Canadian $000s, except per unit
      numbers)
      
      2003
      
      2002[restated-
      Note 3)Net income as
      reported
      $
      33,394
      $
      8,340AdjustmentsDepletion, depreciation and accretion (b)
      
      4,121
      
      6,933FAS
      133 adjustment (c)
      
      620
      
      (27,666)Interest on convertible debentures (g)
      
      (7,341)
      
      (4,901)Non-cash general and administrative (h)
      
      (1,433)
      
      -Future income taxes
      (a) (c) (e)
      
      (6,595)
      
      8,874Income before
      cummulative effect of a change inaccounting policy - U.S. GAAP
      $
      22,766
      $
      (8,420)Net income
      (loss), before change in accountingpolicy, per unit
      - basic and diluted
      $
      0.33
      $
      (0.21)Effect of a
      change in accounting policy due to ARO (b)Depletion, depreciation and accretion
      
      (2,141)
      
      -Future income tax
      recovery
      
      741
      
      -Net income (loss) - U.S. GAAP
      $
      21,366
      $
      (8,240)Net income (loss) per unit -
      basic and diluted
      $
      0.31
      $
      (0.21)
  The application of US GAAP would have the following effects on the balance
  sheet as reported:
As at December 31,2003
      
      
      
      2002Canadian
      
      U.S.
      
      Canadian
      
      U.S.GAAP
      
      GAAP
      
      GAAP
      
      GAAP(restated
      
      (restated-
      Note 3)
      
      -
      Note 3)AssetsProperty, plant
      and equipment (a) (b)
      $
      884,891
      $
      867,703
      $
      719,859
      $
      678,728Liabilities
      and unitholders' equityOther liability
      (c)
      
      -
      
      23,804
      
      -
      
      24,424Asset retirement
      obligation (b)
      
      33,182
      
      33,182
      
      32,645
      
      12,245Future income
      taxes (a) (b) (c) (e)
      
      58,805
      
      44,124
      
      116,846
      
      94,777Convertible
      debentures - long-term liability (g)
      
      -
      
      119,395
      
      -
      
      61,279Convertible
      debentures - equity (g)
      
      119,395
      
      -
      
      61,279
      
      -Accumulated
      interest on convertible debentures - equity (g)
      
      (12,242)
      
      -
      
      (4,901)
      
      -Capital
      contributions (d)
      
      803,299
      
      807,282
      
      513,835
      
      517,818Contributed
      surplus (h)
      
      1,305
      
      2,738Accumulated (loss) income
      $
      (4,029)
      $
      (47,998)
      $
      (37,423)
      $
      (69,364)
  88 | PROVIDENT ENERGY TRUSTANNUAL REPORT 2003 | 89
(a) The Canadian cost recovery ceiling test limits the capitalized costs
  for each cost centre to the undiscounted future net revenue from proved oil
  and natural gas reserves plus the cost of unproved properties less impairment,
  using year end prices. In addition, the aggregate value of all cost centres is
  further limited by including financing costs, administrative expenses, future
  abandonment and reclamation costs and income taxes. 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 and
  financing and administrative expenses are excluded from the calculation. 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.
  (b) Provident adopted the Canadian accounting standard for
  Asset Retirement Obligation (ARO), as outlined in CICA handbook section 3110
  effective December 2003. This section is equivalent to Statement of Financial
  Accounting Standards (FAS) No.143, Accounting for Asset Retirement Obligations
  which was effective for fiscal periods beginning on or after January 1, 2003.
  Adoption of this standard in 2003 eliminated a US GAAP reconciling item
  related to accounting for the obligation, however, a difference is created in
  how the transition amounts are disclosed. US GAAP requires that the cumulative
  impact of a change in accounting policy be presented in the current year
  Consolidated Statement of Operations and Accumulated Loss and prior periods
  not be restated.
  (c) Since inception, Provident adopted FAS 133, Accounting for Financial
  Instruments and Hedging Activities, which requires that all derivatives be
  recorded on the balance sheet at their fair value, as either an asset or
  liability. Changes in the derivative's fair value are recognized in the
  current period earnings, unless specific hedge accounting criteria are met. If
  the derivative is designated a fair value hedge, the changes in the fair value
  of the derivative and the hedged item attributable to the hedged risk are
  recognized in earnings. If the derivative is designated a cash flow hedge, the
  effective portions of the changes in fair value of the derivative are recorded
  in other comprehensive income and are recognized in earnings when the hedge
  item is realized. Ineffective portions of change in fair value are recognized
  in earnings immediately. The mark to market at the balance sheet dates of
  financial contracts have been reflected in these adjustments. Pursuant to
  Canadian GAAP, no mark to market is recognized in the financial statements.
  (d) Under U.S. GAAP, costs associated with a plan of arrangement would be
  expensed. Under Canadian GAAP, the costs are offset to capital contributions.
  (e) The Canadian liability method of accounting for 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.
  (f) The consolidated statements of cash flows prepared in accordance with
  Canadian GAAP conform in all material respects with U.S. GAAP except that
  Canadian GAAP allows for the presentation of operating cash flow before
  changes in non-cash working capital items in the consolidated statement of
  cash flows. This total cannot be presented under U.S. GAAP. U.S. GAAP would
  require this statement to be a note to the financial statements.
  (g) Under U.S. GAAP, convertible debentures are treated as
  debt and any distributions paid on these debentures are treated as interest
  expense. Under Canadian GAAP, convertible debentures are classified as equity
  and any distributions are recorded as a direct charge to unitholders' equity.
  (h) Provident harmonized its accounting treatment of unit based
  compensation with US GAAP in 2003 by adopting CICA handbook section 3870,
  "Stock-based compensation and other stock-based payments." For US GAAP
  purposes Provident follows FAS 123, "Accounting for stock-based compensation."
  Adoption of CICA handbook section 3870 allows for prospective application
  whereby only 2003 option grants are fair valued. Under FAS 123, all option
  grants are fair valued.
Recent US accounting pronouncements
Accounting for certain financial instruments with
  characteristics of both liabilities and equityIn 2003, the Financial Accounting Standards Board (FASB)
  issued FAS 150, "Accounting for Certain Financial Instruments with
  Characteristics of Liabilities and Equity." FAS 150 establishes standards for
  the measurement and classification of certain financial instruments with
  characteristics of both liabilities and equity. Provident adopted this
  standard with no impact to the consolidated financial statements.
PROVIDENT ENERGY TRUST |
    89
90 | ANNUAL REPORT 2003Recent US accounting pronouncements issued but not implementedIn 2003, FASB issued Interpretation Number 46R, "Consolidation of Variable
Interest Entities, an interpretation of Accounting Research Bulletin No. 51."
The standard mandates that variable interest entities be consolidated by their
primary beneficiary. In Canada, the Accounting Standards Board (ACSB) has
suspended the effective dates for accounting guideline 15, "Consolidation of
Variable Interest Entities" to amend the guideline to harmonize it with FAS
Interpretation Number 46R. At December 31, 2003 Provident did not have any
variable interests in special purpose entities.
Recent Canadian accounting pronouncements issued but not implemented
Full cost accountingIn 2003, the CICA issued accounting guideline 16, "Oil and Gas Accounting
  -
  Full Cost." This accounting guideline replaces accounting guideline 5, "Full
  cost accounting in the oil and gas industry." The guideline alters the ceiling
  test calculation and is effective for fiscal years beginning on or after
  January 1, 2004. Accounting guideline 16 does not harmonize Canadian and US GAAP as US GAAP requires the ceiling test to be performed using a 10% discount
  rate while accounting guideline 16 requires that management's best estimate
  for fair value be used.
  Exchangeable sharesIn 2003, the CICA issued a draft EIC, "Income trusts -
  exchangeable shares." The EIC proposes that the retained interest of the
  exchangeable shareholders should be presented on the balance sheet as a
  non-controlling interest separate and distinct from unitholders' equity. The
  draft EIC is currently under review and was not enacted in final form as of
  the time of publication of Provident's consolidated financial statements.
  Convertible debenturesIn 2005, in accordance with CICA Handbook section 3860, "Financial
  instruments - disclosure and presentation," convertible debentures will be
  required to be classified as a liability on the balance sheet with interest
  payment recorded as an expense. For US GAAP, Provident classifies convertible
  debentures as liabilities on the balance sheet and records interest payments
  on convertible debentures as an expense.
  Hedging relationshipsCICA accounting guideline 13, "Hedging relationships" is effective for
  fiscal periods beginning on or after July 1, 2003. This accounting guideline
  addresses the identification, designation, documentation and effectiveness of
  hedging relationships, for the purpose of applying hedge accounting. In
  addition, it establishes criteria for discontinuing the use of hedge
  accounting. Under accounting guideline 13, hedging transactions must be
  documented and it must be demonstrated that the hedges are sufficiently
  effective to continue accrual accounting for positions hedged with
  derivatives. Provident does not anticipate applying hedge accounting to its
  commodity price risk management program. Therefore, Provident expects to
  eliminate the US GAAP difference, "FAS 133 adjustment" (item (c) above) in
  2004 and charge the mark to market amounts to the Canadian GAAP income
  statement.
90 | PROVIDENT ENERGY TRUST

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, 2003, 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 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 recorded,
processed, summarized and reported within the time periods specified in
Securities and Exchange Commission rules and forms.

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) Changes in Internal Control Over
Financial Reporting. During the fiscal year ended December 31, 2003, 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).

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.

Since the adoption of the Code of Ethics, 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 following table provides information about
the fees billed to the registrant for professional services rendered by
PricewaterhouseCoopers LLP during fiscal 2003 and 2002:

|(CDN$)             |   | 2003    |   | 2002   
|------------------ | - | ------- | - | -------
|Audit Fees         | $ | 334,600 | $ | 247,300
|Audit-Related Fees |   | 167,500 |   | 50,300 
|Tax Fees           |   | 214,700 |   | 130,000
|All Other Fees     |   | -       |   | -      
|Total              |   | 716,800 |   | 427,600

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.

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. During fiscal 2003 and 2002, the services
provided in this category included due diligence reviews in connection with
acquisitions, research of accounting and audit-related issues, review of
reserves disclosure and the completion of audits required by contracts to which
the registrant is a party.

Tax Fees. Tax fees consist of fees for tax
compliance services, tax advice and tax planning. During fiscal 2003 and 2002,
the services provided in this category included assistance and advice in
relation to the preparation of corporate income tax returns.

All Other Fees. There are no other fees.

Pre-Approval Policies and Procedures.

(a)

---

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.$50,000.
  Amounts exceeding Cdn.$50,000 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", none of the fees billed by PricewaterhouseCoopers LLP were approved
  by the audit committee of the registrant pursuant to the de minimus
  exception 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 arrangements that have or are reasonably likely to have a current or
future effect on the registrant's financial condition, changes in financial
condition, revenues or expenses, results of operations, liquidity, capital
expenditures or capital resources that is material to investors.Tabular Disclosure of Contractual Obligations.

|(CDN$ millions)                             |       | Payment due by
    period |      
|------------------------------------------- | ----- | ------------------------- | -----
|                                            |       | Less than 1               | 1-3  
|Contractual
    Obligations                 | Total | Year                      | Years
|Long-Term Debt
    Obligations              | 236.5 | -                         | 236.5
|Capital (Finance) Lease
    Obligations     | -     | -                         |      
|Operating Lease
    Obligations             | 21.6  | 2.3                       | 4.7  
|Purchase Obligations                        | -     | -                         | -    
|Other Long-Term
    Liabilities Reflected   |       | -                         | -    
|on the Registrant's
    Balance Sheet under |       |                           |      
|Canadian GAAP                               |       |                           |      
|Total                                       | 258.1 | 2.3                       | 241.2

---

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 April 26, 2004.

PROVIDENT
      ENERGY TRUSTBy: Provident
      Energy Ltd.By: /s/ Thomas
      W. BuchananName: Thomas W.
      BuchananTitle: 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    | Section
    1350 Certification of Chief Executive Officer                           
|        |                                                                                     
|99.4    | Section
    1350 Certification of Chief Financial Officer                           
|        |                                                                                     
|99.5    | Consent
    of PricewaterhouseCoopers LLP                                           
|        |                                                                                     
|99.6    | Consent
    of Ernst & Young LLP                                                    
|        |                                                                                     
|99.7    | Consent
    of McDaniel & Associates Consultants Ltd.                               

---