---

U.S. SECURITIES AND EXCHANGE COMMISSION 
Washington, D.C. 20549

FORM 40-F

(Check One)

[

or

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

For the fiscal year ended December 31, 2004

Commission file number 1-15196

PROVIDENT ENERGY TRUST 

(Exact name of registrant as specified in its charter)

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

Suite 800, 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, 2004: 142,226,248
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, 2004;                                                                                                                                   
|--- | -----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
|    |                                                                                                                                                                                                            
|(b) | Management's Discussion and Analysis of Financial Condition andResults of Operations for the fiscal year ended December 31, 2004; and                                                                      
|    |                                                                                                                                                                                                            
|(c) | Consolidated Financial Statements for the fiscal year ended December 31,2004(Note 20 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, 2004



March 30, 2005

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TABLE OF CONTENTS

|                                            | Page |                                               | Page
|------------------------------------------- | ---- | --------------------------------------------- | ----
|                                            |      |                                               |     
|GLOSSARY OF TERMS                           | 1    | Reserves and Future Net Revenue               | 40  
|ABBREVIATIONS, TERMS AND                    |      | Reconciliation of Changes in
    Reserves and |     
|CONVERSIONS                                 | 5    | Future Net Revenue                            | 46  
|PRESENTATION OF OIL AND GAS                 |      | Undeveloped Reserves                          | 49  
|RESERVES AND PRODUCTION                     |      | Future Development Costs                      | 50  
|INFORMATION                                 | 6    | Abandonment and Reclamation
    Costs         | 51  
|NON-GAAP MEASURES                           | 6    | Forward Contracts                             | 51  
|NOTE REGARDING FORWARD                      |      | Significant Factors or
    Uncertainties      | 51  
|LOOKING STATEMENTS                          | 6    | Oil and Gas Properties and Wells              | 51  
|INCORPORATION AND STRUCTURE                 | 9    | Significant Properties                        | 52  
|The Trust                                   | 9    | Properties with No Attributed
    Reserves    | 52  
|Provident                                   | 9    | Costs Incurred                                | 53  
|Provident Holdings Trust                    | 9    | Exploration and Development
    Activities    | 53  
|Provident Acquisitions L.P                  | 9    | Production Estimates                          | 53  
|Provident Acquisitions Inc                  | 9    | Production History                            | 54  
|Breitburn Energy Company L.P                | 10   | MIDSTREAM NGL PROCESSING                      |     
|INTERCORPORATE RELATIONSHIPS                | 10   | OPERATIONS                                    | 56  
|INFORMATION CONCERNING THE                  |      | General                                       | 56  
|TRUST, PROVIDENT AND                        |      | NGL Extraction                                | 56  
|CERTAIN SUBSIDIARIES                        | 11   | NGL Fractionation                             | 57  
|Provident Energy Trust                      | 11   | NGL Transportation                            | 57  
|Provident Energy Ltd                        | 17   | NGL Storage                                   | 57  
|Provident Holdings Trust and
    Provident  |      | NGL Marketing                                 | 57  
|Acquisitions L.P                            | 23   | Commercial Arrangements                       | 58  
|Provident Acquisitions Inc                  | 23   | MARKET FOR SECURITIES                         | 59  
|Breitburn Energy Company L.P                | 23   | RECORD OF CASH DISTRIBUTIONS                  | 60  
|Internalization of Management               | 23   | DIRECTORS AND OFFICERS                        | 61  
|GENERAL DEVELOPMENT OF THE                  |      | AUDIT COMMITTEE INFORMATION                   | 68  
|BUSINESS OF THE TRUST AND                   |      | INFORMATION CONCERNING THE OIL                |     
|PROVIDENT                                   | 25   | AND GAS INDUSTRY                              | 69  
|SIGNIFICANT ACQUISITIONS                    | 28   | RISK FACTORS                                  | 71  
|Founders Arrangement                        | 28   | Oil and Gas Production Risk
    Factors       | 72  
|Maxx Arrangement                            | 29   | Midstream NGL Asset Risk Factors              | 74  
|Richland Arrangement                        | 29   | General Risk Factors                          | 76  
|Southeast Alberta Property
    Acquisition  | 30   | INTERESTS OF MANAGEMENT AND                   |     
|Meota Takeover                              | 30   | OTHERS IN MATERIAL                            |     
|Redwater Acquisition                        | 31   | TRANSACTIONS                                  | 80  
|Viracocha Arrangement                       | 32   | TRANSFER AGENT AND REGISTRAR                  | 80  
|Olympia Arrangement                         | 33   | INTERESTS OF EXPERTS                          | 80  
|Breitburn Acquisition                       | 34   | MATERIAL CONTRACTS                            | 80  
|CORPORATE STRATEGY AND RISK                 |      | DOCUMENTS INCORPORATED BY                     |     
|MANAGEMENT                                  | 35   | REFERENCE                                     | 81  
|General                                     | 35   | PRINCIPAL HOLDERS OF TRUST                    |     
|Commodity Price Risk Management
    Program | 35   | UNITS                                         | 81  
|OIL AND NATURAL GAS OPERATIONS              | 38   | ADDITIONAL INFORMATION                        | 81  
|Principal Properties                        | 38   |                                               |     

|             |                                                                  
|------------ | -----------------------------------------------------------------
|SCHEDULE A - | REPORTS ON RESERVES DATA BY INDEPENDENT
    QUALIFIED RESERVES   
|             | EVALUATOR OR AUDITOR                                             
|SCHEDULE B - | REPORT OF MANAGEMENT AND DIRECTORS ON
    RESERVES DATA AND OTHER
|             | INFORMATION                                                      
|SCHEDULE C - | AUDIT COMMITTEE INFORMATION                                      
|SCHEDULE D - | FINANCIAL STATEMENTS OF OLYMPIA ENERGY INC.                      
|SCHEDULE E - | FINANCIAL STATEMENTS OF VIRACOCHA ENERGY INC.                    
|SCHEDULE F - | FINANCIAL STATEMENTS OF BREITBURN ENERGY
    COMPANY LLC         

-i-

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GLOSSARY OF TERMS
"ABCA" means the Business Corporations Act (Alberta), S.A. 1981, c.
B-15, as amended, including the regulations promulgated thereunder;
"Accrete" means Accrete Energy Inc., formerly 1101130 Alberta Ltd.;
"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;
"Breitburn L.P." means Breitburn Energy Company L.P., a Delaware limited
partnership and an indirect subsidiary of the Trust;
"Breitburn" means Breitburn Energy Company LLC, a former California limited
liability company;
"Breitburn Acquisition" means the transaction in which the
Trust acquired all of the issued and outstanding shares of Breitburn pursuant to
an agreement and plan of merger dated June 15, 2004 among the Trust, Breitburn,
Pro GP Corp., Pro LP Corp. and BB Merger LLC;
"Breitburn Properties" means the oil and gas properties held by Breitburn
L.P. in the state of California with minor interests offshore in the Gulf of
Mexico and the State of Wyoming;
"Budget" means the Notice of Ways and Means Motion released as an annex to
the March 23, 2004 Canadian Federal Budget;
"6.5% Debentures" means the 6.5% convertible unsecured subordinated
debentures of the Trust;
"8% Debentures" means the 8% convertible unsecured
subordinated debentures of the Trust;
"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;
"CGA"
means Cawley, Gillespie and Associates, Inc., independent petroleum engineers;
"Chamaelo"
means Chamaelo Energy Inc., formerly 1100974 Alberta Inc.;
"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;

- 1 -

---

"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;
"GLJ" means Gilbert Laustsen Jung Associates Ltd., independent petroleum
engineers;
"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
February 25, 2005 effective December 31, 2004;
"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;
"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;
"NSA" means Netherland, Sewell and Associates, Inc., independent petroleum
engineers;
"Nautilus" means Nautilus Resources LLC;
"Nautilus Acquisition" means the acquisition of all of the
membership interests in Nautilus by Breitburn L.P. pursuant to a membership
interest purchase and sale agreement dated February 9, 2005 among Breitburn L.P.
and all of the membership interest holders of Nautilus;
"Nautilus Properties" means the oil and gas producing properties in the State
of Wyoming held by Nautilus and acquired by Breitburn L.P. pursuant to the
Nautilus Acquisition;
"Non-Resident" means a non-resident of Canada for the purposes of the Tax
Act;
"Olympia" means Olympia Energy Inc.;
"Olympia Arrangement" means the plan of arrangement in which
the Trust acquired all of the issued and outstanding common shares of Olympia
pursuant to an arrangement agreement dated April 6, 2004 among the Trust,
Provident, Olympia and Accrete;
"Opal" means Opal Energy Inc.;
- 2 -"Option Plan" means the trust unit option plan of the Trust providing for the
issuance of options to acquire Trust Units to employees, officers, directors and
consultants of the Trust;
"Orcutt Hill Acquisition"means the acquisition by Breitburn
L.P. of certain oil and natural gas producing properties, related interests and
5,000 acres of surface acreage situated in the Orcutt Hill Oil Field located in
Santa Barbara County, California pursuant to a purchase and sale agreement dated
September 13, 2004 between Breitburn L.P. and an arm's length third party
vendor;
"Orcutt Hill Properties"means the oil and natural gas
producing properties, related interests and 5,000 acres of surface acreage
situated in the Orcutt Hill Oil Field located in Santa Barbara County,
California acquired by Breitburn L.P. pursuant to the Orcutt Hill Acquisition;
"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;
"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,
- 3 -
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;
"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;
"Viracocha" means Viracocha Energy Inc.;
- 4 -"Viracocha Arrangement" means the plan of arrangement in
which the Trust acquired all of the issued and outstanding common shares of Viracocha pursuant to an arrangement agreement dated April 6, 2004 among the
Trust, Provident, Viracocha and Chamaelo; 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
    Natural Gasbbls
    barrels
    Mcf
    thousand cubic feetMbbl
    thousand barrels
    MMcf
    million cubic feetbpd or bbl/d
    barrels of oil per day
    bcf
    billion cubic feetmmbbls
    million barrels
    mcfd or Mcf/d
    thousand cubic feet per dayNGLs
    natural gas liquids
    mmcfd
    million cubic feet per daySTB
    stock tank barrel of oil
    m3
    cubic metresMstb
    thousand stock tank barrels of
    oil
    mmbtu
    million British Thermal Unitsboed or boe/d
    barrels of oil equivalent per
    day
    GJ
    gigajoulegjpd
    gigajoule per day

|      |                                                                                               
|----- | ----------------------------------------------------------------------------------------------
|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.                                                 
|mmboe | means million 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 | To           | Multiply By
|--------------- | ------------ | -----------
|mcf             | cubic metres | 0.0282     
|cubic metres    | cubic feet   | 35.494     
|Bbls            | cubic metres | 0.159      
|cubic metres    | bbls         | 6.289      
|feet            | metres       | 0.305      
|metres          | feet         | 3.281      
|miles           | kilometres   | 1.609      
|kilometres      | miles        | 0.621      
|acres           | hectares     | 0.405      
|hectares        | acres        | 2.471      
|gigajoules      | mmbtu        | 0.950      

- 5 -

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PRESENTATION OF OIL AND GAS RESERVES AND PRODUCTION
INFORMATION

All oil and natural gas reserve information contained in this
Annual Information Form has been prepared and presented in accordance with
National Instrument 51-101 Standard of Disclosure for Oil and Gas Activities
("NI 51-101"). The actual oil and natural gas reserves and future production
will be greater than or less than the estimates provided in this Annual
Information Form. The estimated future net revenue from the production of the
disclosed oil and natural gas reserves does not represent the fair market value
of these reserves. The Trust has adopted the standard of 6 mcf:1 boe when
converting natural gas to barrels of oil equivalent. Boe may be misleading,
particularly if used in isolation. A boe conversion ratio of 6 mcf:1 boe is
based on an energy equivalency conversion method primarily applicable at the
burner tip and does not represent a value equivalency at the wellhead.

NON-GAAP MEASURES

In this Annual Information Form, the Trust uses the terms
"cash flow", "adjusted cash flow" and "funds flow from operations" to refer to
the amount of cash available for distribution to Unitholders and as indicators
of financial performance. "Cash flow", "adjusted cash flow" and "funds flow from
operations" are not measures recognized by Canadian generally accepted
accounting principles ("GAAP") and do not have standardized meanings prescribed
by GAAP. Therefore, "cash flow", "adjusted cash flow" and "funds flow from
operations" of the Trust may not be comparable to similar measures presented by
other issuers, and investors are cautioned that "cash flow", "adjusted cash
flow" and "funds flow from operations" should not be construed as alternatives
to net earnings, cash flow from operating activities or other measures of
financial performance calculated in accordance with GAAP. All references to
"cash flow", "adjusted cash flow" and "funds flow from operations" are based on
cash flow before changes in non-cash working capital related to operating
activities and site restoration expenditures, as presented in the consolidated
financial statements of the Trust. The actual amount of cash that is distributed
cannot be assured and future distributions may vary. The Trust uses such terms
as an indicator of financial performance because such terms are commonly
utilized by investors to evaluate royalty trusts and income funds in the oil and
gas sector. The Trust believes that such terms are useful supplemental measures
as they provide investors with information of what cash is available for
distribution from the Trust to Unitholders in such periods.

NOTE REGARDING FORWARD LOOKING STATEMENTS

This 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 ability to benefit from the combination of growth
  opportunities and the ability to grow through the capital markets;
- the Trust's acquisition strategy, the criteria to be
  considered in connection therewith and the benefits to be derived therefrom;

- 6 -

---



- 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
- 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
  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 impact of environmental
  events;
- the need to obtain required
  approvals from regulatory authorities;
- unanticipated operating events
  which can reduce production or cause production to be shut-in or delayed;
- failure to 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.

- 7 -

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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.

- 8 -

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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. Provident was amalgamated with Viracocha and Olympia
effective June 1, 2004 pursuant to the Viracocha Arrangement and Olympia
Arrangement, respectively. 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.

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Breitburn Energy Company L.P.

Breitburn L.P. is a Delaware limited partnership and an
indirect subsidiary of the Trust. Breitburn L.P. resulted from the merger of
Breitburn, a former California limited liability company, and BB Merger LLC, a
Delaware limited liability company and wholly-owned indirect subsidiary of the
Trust, pursuant to the Breitburn Acquisition. The Trust currently indirectly
holds approximately 95% of the outstanding partnership interests of Breitburn
L.P. with the remaining approximately 5% of the partnership interests held by
Breitburn's co-founders and co-chief executive officers. The head and principal
offices of Breitburn L.P. are located at 515 S. Flower Street, Suite 4800, Los
Angeles, California 90071. The registered office of Breitburn L.P. is 2711
Centerville Road, Suite 400, Willington, Delaware 19808.

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.



Notes: 
(1) Portion of cash flow withheld to fund capital expenditures, reclamation fund
and debt repayment. 
(2) Controlled by Breitburn's co-founders.

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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 and the Trust's various subsidiaries
to the Trust by way of royalty payments and interest payments and principal
repayments on notes issued by the Trust from time to time. Cash flow from the
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 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.

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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 March
19, 2005, 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
March 22, 2005, there was $45,696,500 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
March 22, 2005, there was $74,117,000 aggregate principal amount of 8.75%
Debentures outstanding.

> 8% Debentures

In July 2004, the Trust issued $50,000,000 aggregate
principal amount of convertible unsecured subordinated debentures. The 8%
Debentures mature on July 31, 2009 and bear interest at a rate of 8% per annum,
payable semi-annually in arrears on July 31 and January 31 in each year. The 8%
Debentures are convertible at the option of the holder into Trust Units at any
time prior to the earlier of July 31, 2009 and the business day immediately
preceding any date specified by the Trust for redemption at a conversion price
of $12.00 per Trust Unit, subject to adjustment in certain circumstances. After
July 31, 2007 and prior to maturity, the Trust may redeem the 8% Debentures in
whole or in part from time to time at a price of $1,050 per 8% Debenture from
July 31, 2007 until July 31, 2008 and at a price of $1,025 per 8% Debenture
thereafter until maturity, in each case plus accrued and unpaid interest. On
redemption or maturity of the 8% Debentures, the Trust may, subject to
regulatory approval, elect to

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satisfy the redemption price or principal amount by issuing Trust Units to
the 8% Debenture holder. As of March 19, 2005, there was $50,000,000 aggregate
principal amount of 8% Debentures outstanding.

> 6.5% Debentures

In March 2005, the Trust issued $100,000,000 aggregate
principal amount of convertible unsecured subordinated debentures. The 6.5%
Debentures mature on August 31, 2012 and bear interest at a rate of 6.5% per
annum, payable semi-annually in arrears on August 31 and February 28 in each
year, commencing August 31, 2005. The 6.5% Debentures are convertible at the
option of the holder into Trust Units at any time prior to the earlier of August
31, 2012 and the business day immediately preceding any date specified by the
Trust for redemption at a conversion price of $13.75 per Trust Unit, subject to
adjustment in certain circumstances. After August 31, 2008 and prior to
maturity, the Trust may redeem the 6.5% Debentures in whole or in part from time
to time at a price of $1,050 per 6.5% Debenture from August 31, 2008 until
August 31, 2009, at a price of $1,025 per 6.5% Debenture after August 31, 2009
and on or before August 31, 2010 and after August 31, 2010 and prior to maturity
at a price of $1,000 per 6.5% Debenture, in each case plus accrued and unpaid
interest. On redemption or maturity of the 6.5% Debentures, the Trust may,
subject to regulatory approval, elect to satisfy the redemption price or
principal amount by issuing Trust Units to the 6.5% Debenture holder. As of
March 19, 2005, there was $100,000,000 aggregate principal amount of 6.5%
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 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.

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Trust Unit Option Plan

The Trust has implemented a trust unit option plan. Under the
Option Plan, options to purchase a maximum of 8,000,000 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 8,000,000 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 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 March 23, 2005, there were 4,903,043 options granted and outstanding under
the Option Plan.

> Premium Distribution, Distribution Reinvestment and Optional Unit Purchase
> Plan

The Trust has implemented a premium distribution,
distribution reinvestment and optional unit purchase plan (the "DRIP") to
provide holders of Trust Units with a means to automatically reinvest sums
received on account of distributions on Trust Units. Provident reserves the
right to prorate the participation in the DRIP to manage the amount of cash
reinvested in the Trust and the Trust Units issued under the DRIP. Computershare
Trust Company of Canada, as plan agent, may at the election of a participant (a)
purchase Trust Units with the cash distributions at 95% 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")

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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.

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".

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March 2004 Federal Budget

The Budget, and subsequent announcements by the Department of
Finance which withdrew certain of the Budget proposals, proposed changes to the
Tax Act that will result in distributions to non-residents made after 2004,
other than distributions out of the income of the Trust (which are already
subject to Canadian withholding tax) becoming 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.
The Budget originally included a number of proposals relating to non-resident
ownership of mutual fund trusts. However, these proposals were withdrawn by
subsequent announcements by the Department of Finance.

> 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.

> 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

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the Trust or the Trust Fund, arising from the exercise by the
Trustee of any powers, authorities or discretion conferred under the Trust
Indenture, unless such liabilities arise out of the gross negligence, wilful
default or fraud of the Trustee or any of its directors, officers, employees,
shareholders or agents. In the exercise of the powers, authorities or discretion
conferred upon the Trustee under the Trust Indenture, the Trustee is and shall
be conclusively deemed to be acting as Trustee of the assets of the Trust and
shall not be subject to any personal liability for any debts, liabilities,
obligations, claims, demands, judgements, costs, charges or expenses against or
with respect to the Trust or the Trust Fund. In addition, the Trust Indenture
contains other customary provisions limiting the liability of the Trustee.

> Amendments to the Trust Indenture

The Trust Indenture may be amended or altered from time to
time by Special Resolution. The Trustee may, without the approval of the
Unitholders, make certain amendments to the Trust Indenture, including
amendments for the purpose of:

- ensuring the Trust's continuing compliance with applicable laws or
  requirements of any governmental agency or authority of Canada or of any
  province;
- ensuring that the Trust will satisfy the provisions of each of subsections
  108(2) and 132(6) of the Tax Act as from time to time amended or replaced;
- ensuring that such additional protection is provided for interests of
  Unitholders as the Trustee may consider expedient;
- removing or curing any conflicts or inconsistencies between
  the provisions of the Trust Indenture or any supplemental indenture and any
  other agreement of the Trust or any offering document pursuant to which
  securities of the Trust are issued, or any applicable law or regulations of
  any jurisdiction, provided that in the opinion of the Trustee the rights of
  the Trustee and of the Unitholders are not prejudiced thereby; and
- curing, correcting or rectifying any ambiguities, defective
  or inconsistent provisions, errors, mistakes or omissions, provided that in
  the opinion of the Trustee the rights of the Trustee and of the Unitholders
  are not prejudiced thereby.

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,
exploitation, development and production of crude oil and natural gas in the
Western Canadian Sedimentary Basin. Provident currently has 377 employees,
consultants and contract operators at its head office location and 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;

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(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 excess of an amount equal to 5%
of the market capitalization of the 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.

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.

> Series A Exchangeable Shares

Provident also issued a total of 1,682,242 Series A
exchangeable shares in 2003. All of the Series A 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 Series A 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 Series A 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
Series A 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

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Units (rounded down to the nearest whole number) into which the Series A
exchangeable shares are then exchangeable.

The Series A exchangeable shares have substantially similar
attributes to the Series B exchangeable shares issued by Provident in connection
with the Viracocha Arrangement and Olympia Arrangement and described below.

Provident is authorized to issue an unlimited number of
exchangeable shares, issuable in series. As of March 24, 2005, there were
638,474 Series A exchangeable shares of Provident outstanding at an exchange
ratio of 1.391620.

> Series B Exchangeable Shares

On June 1, 2004, Provident issued 2,650,000 Series B
exchangeable shares as partial consideration pursuant to the Viracocha
Arrangement and Olympia Arrangement. The exchange ratio for the Series B
exchangeable shares was initially equal to one Trust Unit for one Series B
exchangeable share and is increased on each date a distribution is paid by the
Trust following the date of issuance and the date the Series B exchangeable
share is exchanged, at the option of the holder, into Trust Units. On January
15, 2006, all remaining Series B exchangeable shares will be automatically
exchanged for Trust Units, subject to extension at the option of the Trust. As
of March 24, 2005, there were 1,295,776 Series B exchangeable shares of
Provident outstanding at an exchange ratio of 1.099790.

The Series B exchangeable shares rank prior to any common
shares of Provident and any other shares ranking junior to the Series B
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 Provident.

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

Subject to the Retraction Call Right described below, a
holder of Series B exchangeable shares is entitled at any time to require
Provident to redeem any or all of the Series B 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.

Holders of the Series B exchangeable shares may request
redemption by presenting to Provident or the Series B exchangeable shares
transfer agent a certificate or certificates representing the number of Series B
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 Series B exchangeable shares. The
redemption will become effective five business days after the date on which
Provident or the Series B exchangeable shares transfer agent receives the
retraction request from the holder.

When a holder requests Provident to redeem the Series B
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 Series B
exchangeable shares that the holder has requested Provident to redeem at a
purchase price per Series B 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.

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At the time of a retraction request by a holder of Series B
exchangeable shares, Provident 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 Provident 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 Series B exchangeable shares will neither be
purchased by the Trust, Provident or a subsidiary of either the Trust or
Provident, nor be redeemed by Provident. If the holder does not revoke his or
her retraction request, the Series B exchangeable shares that the holder has
requested Provident 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
Provident, 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.

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

1. will, on January 15, 2006 (the "Automatic Redemption
  Date"), redeem all but not less than all of the then outstanding Series B
  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;
2. may, at any time when the aggregate number of issued and
  outstanding Series B exchangeable shares is less than 10% of the number of
  Series B exchangeable shares issued (as such number of shares may be adjusted
  as deemed appropriate by the board of directors of Provident to give effect to
  any subdivision or consolidation of or stock dividend on the Series B
  exchangeable shares, any issuance or distribution of rights to acquire Series
  B exchangeable shares or securities exchangeable for or convertible into or
  carrying rights to acquire Series B 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 Series B 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 Series B exchangeable
  shares for the Redemption Price per exchangeable share; and
3. will be deemed to have redeemed all but not less than all
  of the then outstanding Series B 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.

Provident will, at least 90 days prior to any Redemption
Date, provide the registered holders of the Series B exchangeable shares with
written notice of the prospective redemption of the Series B exchangeable shares
by Provident, including the number of Series B exchangeable shares Provident
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 Series
B exchangeable shares and such other documents as may be required at the
registered office of Provident or the office of the Series B exchangeable shares
transfer agent, Provident will deliver the Redemption Price to the holder at the
address of the holder recorded in

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Provident's security register or by holding the Redemption
Price for pick-up by the holder at the registered office of Provident or the
office of the Series B 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 Series B exchangeable shares
(other than the Trust) will not affect the validity of any redemption of Series
B 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 Series B exchangeable shares by
Provident 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
Series B exchangeable shares then outstanding (other than Series B 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 Series B
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, Provident's right to redeem the Series B
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.

Series B 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 Series B 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
Series B 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 Series B exchangeable shares.

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

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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 Series B exchangeable shares to exercise votes
attached to the Special Voting Unit will cease upon the exchange of all such
holder's Series B 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 Series B
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 Series B exchangeable shares), the voting
and exchange trust agreement may not be amended without the approval of the
holders of the Series B exchangeable shares.

The rights, privileges, restrictions and conditions attaching
to the Series B 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 Series B 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 Series B exchangeable shares duly called and held
at which holders of at least 20% of the then outstanding Series B 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 Series B 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 than two-thirds of the
votes cast thereon will constitute the approval or consent of the holders of the
Series B exchangeable shares.

> 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

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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.

Provident Holdings Trust and Provident Acquisitions L.P.

Provident LP holds certain southeast Alberta properties
acquired on May 1, 2002. See "Significant Acquisitions" 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. 10101150 Saskatchewan Ltd. holds the remaining 99.9999%
interest in the Meota (2000) Partnership. PAI has granted a royalty to the Trust
entitling the Trust to receive the cash flow from all present and future oil and
gas properties and related tangibles owned by PAI after certain cost
expenditures and deductions.

On October 1, 2002, PAI issued 5,585,136 million exchangeable
shares as partial consideration for the acquisition of Meota. On January 15,
2005, all remaining exchangeable shares of PAI were automatically exchanged for
Trust Units.

Breitburn Energy Company L.P.

Breitburn L.P. holds the Breitburn Properties acquired
pursuant to the Breitburn Acquisition and the Orcutt Hill Properties acquired
pursuant to the Orcutt Hill Acquisition. Breitburn L.P. also holds all of the
membership interests of Nautilus, which holds oil and gas producing properties
in the State of Wyoming. The Trust currently indirectly holds approximately 95%
of the outstanding partnership interests of Breitburn L.P. with the remaining
approximately 5% of the partnership interests held by Breitburn's co-founders
and co-chief executive officers. Cash flow from the oil and gas properties and
related tangibles held by Breitburn L.P. is distributed to Breitburn L.P.'s
owners, Breitburn Energy Corporation, Pro LP Corp. and Pro GP Corp. and from Pro
LP Corp. and Pro GP Corp. to the Trust in the form of dividends and interest
payments on intercompany debt.

Breitburn L.P. currently has 37 employees and continues to operate and report
as a separate business unit of the Trust.

Internalization of Management

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.

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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 Series A exchangeable shares at an agreed upon price of $10.70 per
share, subject to certain adjustments. Each Series A 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 Series A 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
Series A exchangeable shares issued pursuant to the share purchase agreement
being held in escrow. The number of Series A 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 Series A 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 Series A exchangeable shares effectively releases to
the Vendors the distributions paid on the Trust Units. The number of Series A
exchangeable shares to be released from escrow to account for such distributions
on the Trust Units shall be determined by multiplying the number of Series A
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 Series A 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
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 Series A 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.

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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 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

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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 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.

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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.

On April 6, 2004, the Trust, Provident, Olympia and Accrete
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 the
Olympia Arrangement. In connection with the Olympia Arrangement, certain
exploration and development properties of Olympia were transferred to Accrete, a
newly created company, the shares of which were distributed to Olympia's
shareholders under the Olympia Arrangement. On May 27, 2004, shareholders of
Olympia approved the Olympia Arrangement. On June 1, 2004, the Trust, Provident,
Olympia and Accrete completed the Olympia Arrangement. Provident and Olympia
were then amalgamated and continued as Provident Energy Ltd.

On April 6, 2004, the Trust, Provident, Viracocha and
Chamaelo 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 the Viracocha Arrangement. In connection with the Viracocha
Arrangement, certain exploration and development properties of Viracocha in
Alberta were transferred to Chamaelo, a newly created company, the shares of
which were distributed to Viracocha's shareholders under the Viracocha
Arrangement. On May 27, 2004, shareholders of Viracocha approved the Viracocha
Arrangement. On June 1, 2004, the Trust, Provident, Viracocha and Chamaelo
completed the Viracocha Arrangement. Provident and Viracocha were then
amalgamated and continued as Provident Energy Ltd.

On June 15, 2004, the Trust entered into an agreement and
plan of merger among Breitburn, a California limited liability company, Pro GP
Corp. ("Pro GP"), a Delaware corporation and wholly-owned indirect subsidiary of
the Trust, Pro LP Corp. ("Pro LP"), a Delaware corporation and wholly-owned
indirect subsidiary of the Trust and BB Merger LLC ("Acquisition LLC"), a
Delaware limited liability company and wholly-owned indirect subsidiary of the
Trust, pursuant to which the Trust acquired all of the issued and outstanding
shares of Breitburn, for an aggregate purchase price of $155 million in cash and
the assumption of approximately $35 million of working capital deficiency and
financial obligations of

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Breitburn, subject to certain adjustments. Under the terms of
the Breitburn agreement, Breitburn and Acquisition LLC were merged and Breitburn
was converted into Breitburn L.P., a Delaware limited partnership. The Breitburn
Acquisition was completed on June 15, 2004 and resulted in the Trust indirectly
holding 92% of the outstanding partnership interests of Breitburn L.P. as of
that date, with the remaining 8% of the outstanding partnership interests of
Breitburn L.P. retained by Breitburn's cofounders and co-chief executive
officers for an aggregate purchase price of $13.7 million.

In connection with the Breitburn Acquisition, the Trust
completed a public offering on July 6, 2004 of 13,100,000 Trust Units and
$50,000,000 principal amount of 8% Debentures for gross proceeds of
$186,240,000. The net proceeds from the offering were used to fund the Breitburn
Acquisition, to fund the Trust's capital expenditure program and for general
corporate purposes.

On September 13, 2004, Breitburn L.P., entered into a
purchase and sale agreement with an arm's length third party vendor pursuant to
which Breitburn L.P. agreed to purchase the Orcutt Hill Properties, consisting
of certain oil and natural gas producing properties, related interests and 5,000
acres of surface acreage situated in the Orcutt Hill Oil Field and located in
Santa Barbara County, California for a purchase price of US$45,000,000, subject
to adjustment. The Orcutt Hill Acquisition was completed on October 4, 2004.

In connection with the Orcutt Hill Acquisition, the Trust
completed a public offering on October 4, 2004 of 11,480,000 Trust Units for
gross proceeds of $125,706,000. The net proceeds from the offering were used to
fund the Orcutt Hill Acquisition, to fund the Trust's capital expenditure
program and for general corporate purposes.

On February 9, 2005, Breitburn L.P., entered into a
membership interest purchase and sale agreement with all of the holders of
membership interests in Nautilus pursuant to which Breitburn L.P. agreed to
acquire all membership interests in Nautilus for an aggregate purchase price of
US$75,000,000, subject to adjustment. The Nautilus Acquisition was completed on
March 2, 2005. The reserves attributable to Nautilus were evaluated in
accordance with NI 51-101 by NSA, independent petroleum engineers, in a report
of NSA dated February 9, 2005 and effective January 1, 2005.

In connection with the Nautilus Acquisition, the Trust
completed a public offering on March 1, 2005 of 8,400,000 Trust Units and
$100,000,000 principal amount of 6.5% Debentures for gross proceeds of
$200,800,000. The net proceeds from the offering were used to fund the Nautilus
Acquisition, to fund the Trust's capital expenditure program and for general
corporate purposes.

On March 11, 2005, the Trust announced the appointment of Hugh Fergusson to
the Board of Directors of Provident.

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

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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.

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.

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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 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 the acquisition 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.

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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 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.

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|                  |               |           |                 | 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 | Gathering     | 100%      | NE BC/ NW AB    | -                | -        
|System            |               |           | 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 commercial teams that joined Provident from Williams Canada, all
of whom have significant midstream experience and expertise.

Viracocha Arrangement

On April 6, 2004, the Trust, Provident, Viracocha and
Chamaelo 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 the Viracocha Arrangement. The transaction
was subsequently valued at approximately $210.5 million, including the
assumption by the Trust of $47.7 million of debt and working capital.

On May 27, 2004, shareholders of Viracocha approved the
Viracocha Arrangement under the ABCA involving Viracocha, the Trust, Provident
and Chamaelo. The Plan of Arrangement also received the approval of the Court of
Queen's Bench of Alberta on May 27, 2004.

On June 1, 2004, the Trust and Provident completed the
acquisition of all of the issued and outstanding common shares of Viracocha
pursuant to the Plan of Arrangement. Provident and Viracocha were then
amalgamated and continued as Provident Energy Ltd.

In accordance with the Plan of Arrangement, each share of
Viracocha was exchanged, at the election of each Viracocha shareholder, for (i)
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 up to the date of announcement of the Plan of Arrangement, (ii)
0.248 of a Series B exchangeable share of Provident, or (iii) a combination of
Trust Units and Series B exchangeable shares. Under the Plan of Arrangement, the
number of Series B exchangeable shares issuable to Viracocha shareholders was
limited to 1,325,000. Shareholders of Viracocha also received, for each share of
Viracocha, 0.10 of a share of Chamaelo.

Upon completion of the Plan of Arrangement, an aggregate of
12,758,386 Trust Units and 1,325,000 Series B exchangeable shares were issued to
the former Viracocha shareholders. In lieu of fractional Trust Units or Series B
exchangeable shares, each former Viracocha shareholder otherwise entitled to
receive a fractional Trust Unit or Series B exchangeable share was paid a cash
amount based on the weighted average trading price of the Trust Units on the TSX.

Reserves of Viracocha were evaluated by GLJ effective January 1, 2004 and
results for properties acquired by the Trust were presented in a report dated
June 8, 2004.

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Viracocha was a publicly traded junior oil and gas producer
listed on the TSX engaged in the acquisition, development and exploration for
and production and marketing of, petroleum and natural gas reserves in Alberta
and Saskatchewan. Viracocha's properties significantly overlap with Provident's
existing operations in the Southern and East Central Alberta regions.
Viracocha's Southern Alberta properties, concentrated around Enchant, Badger and
Long Coulee, accounted for 58 percent of production and were weighted 58 percent
light oil and 42 percent natural gas. Viracocha's East Central properties
located near Provost at Battlebend/Choice and Dolcy produce light oil.
Viracocha's heavy oil production is sourced from fields at West Hazel, east of
Lloydminster.

Additional information concerning the Viracocha Arrangement
is set forth in the business acquisition report of the Trust dated June 16, 2004
incorporated by reference herein and filed on SEDAR at www.sedar.com.

Olympia Arrangement

On April 6, 2004, the Trust, Provident, Olympia and Accrete
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 the Olympia Arrangement. The transaction was
subsequently valued at approximately $226.9 million, including the assumption by
the Trust of $54.2 million of debt and working capital.

On May 27, 2004, shareholders of Olympia approved the Olympia
Arrangement under the ABCA involving Olympia, the Trust, Provident and Accrete.
The Olympia Arrangement also received the approval of the Court of Queen's Bench
of Alberta on May 27, 2004.

On June 1, 2004, the Trust and Provident completed the
acquisition of all of the issued and outstanding common shares of Olympia
pursuant to the Olympia Arrangement. Provident and Olympia were then amalgamated
and continued as Provident Energy Ltd.

In accordance with the Plan of Arrangement, each share of
Olympia was exchanged, at the election of each Olympia shareholder, for (i)
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 up to the date of announcement of the Olympia Arrangement, (ii) 0.345 of
a Series B exchangeable share of Provident, or (iii) a combination of Trust
Units and Series B exchangeable shares. Under the Olympia Arrangement, the
number of Series B exchangeable shares issuable to Olympia shareholders was
limited to 1,325,000. Shareholders of Olympia also received, for each share of
Olympia, 0.10 of a share of Accrete.

Reserves of Olympia were evaluated by GLJ effective January 1, 2004 and
results for properties acquired by the Trust were presented in a report dated
June 8, 2004.

Upon completion of the Olympia Arrangement, an aggregate of
13,385,579 Trust Units and 1,325,000 Series B exchangeable shares were issued to
the former Olympia shareholders. In lieu of fractional Trust Units or Series B
exchangeable shares, each former Olympia shareholder otherwise entitled to
receive a fractional Trust Unit or Series B exchangeable share was paid a cash
amount based on the weighted average trading price of the Trust Units on the TSX.

Olympia was a publicly traded junior oil and gas producer
listed on the TSX with revenues primarily derived from oil and gas properties in
Alberta. Olympia's major production properties were located within Provident's
West Central Alberta core area, primarily in the Lochend, Wildcat Hills and
Bottrel areas. Olympia also had production in the Suffield Atlee/Buffalo area as
well as in Northern Alberta in Little Horse and Moon Creek.

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Additional information concerning the Olympia Arrangement is
set forth in the business acquisition report of the Trust dated June 16, 2004
incorporated by reference herein and filed on SEDAR at www.sedar.com.

Breitburn Acquisition

On June 15, 2004, the Trust entered into an agreement and
plan of merger among Breitburn, a California limited liability company, Pro GP
Corp. ("Pro GP"), a Delaware corporation and wholly-owned indirect subsidiary of
the Trust, Pro LP Corp. ("Pro LP"), a Delaware corporation and wholly-owned
indirect subsidiary of the Trust and BB Merger LLC ("Acquisition LLC"), a
Delaware limited liability company and wholly-owned indirect subsidiary of the
Trust, pursuant to which the Trust acquired all of the issued and outstanding
shares of Breitburn, for an aggregate purchase price of $157.4 million in cash
and the assumption of approximately $35 million of working capital deficiency
and financial obligations of Breitburn, subject to certain adjustments. Under
the terms of the Breitburn purchase agreement, Breitburn and Acquisition LLC
were merged and Breitburn was converted into Breitburn L.P., a Delaware limited
partnership.

The Breitburn Acquisition was completed on June 15, 2004 and
resulted in the Trust indirectly holding 92% of the outstanding partnership
interests of Breitburn L.P. as of that date, with the remaining 8% of the
outstanding partnership interests of Breitburn L.P. retained by Breitburn's
co-founders and co-chief executive officers for an aggregate purchase price of
$13.7 million.

Breitburn L.P. holds oil and gas properties in the state of
California with minor interests offshore in the Gulf of Mexico and the state of
Wyoming. The reserves attributable to the Breitburn Properties were evaluated in
accordance with NI 51-101 by NSA and CGA, independent petroleum engineers, in
reports dated June 18, 2004 and June 7, 2004, respectively and effective
December 31, 2003.

Breitburn was one of California's largest independent oil
companies with a business model premised upon the acquisition of under developed
producing properties and the optimization of these mature producing assets
through the use of computerized reservoir engineering tools.

Pursuant to a limited partnership agreement dated as of June
15, 2004 among Pro GP, Pro LP and Breitburn Energy Corporation, Pro GP and Pro
LP, the indirect wholly-owned subsidiaries of the Trust, currently hold
approximately 95% of the outstanding partnership interests in Breitburn L.P.
which continues to hold the Breitburn Properties. Breitburn Energy Corporation,
a California corporation, currently holds approximately 5% of the outstanding
partnership interests of Breitburn L.P.

Breitburn L.P. continues to operate and report as a separate
business unit of the Trust. Mr. Buchanan and Mr. Findlay (directors of
Provident), another appointee of Provident and Breitburn's two co-founders and
co-chief executive officers serve as directors of Pro GP, the managing partner
of Breitburn L.P. Breitburn L.P. has also entered into employment agreements
dated as of June 15, 2004 pursuant to which Breitburn's co-founders and co-chief
executive officers have agreed to act as co-chief executive officers of
Breitburn L.P.

Additional information concerning the Breitburn Acquisition
is set forth in the business acquisition report of the Trust dated August 30,
2004 incorporated by reference herein and filed on SEDAR at www.sedar.com.

- 34 -

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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 and in
the States of California and Wyoming. These areas generally offer low to medium
risk development potential and a well developed operational infrastructure, 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 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.

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> 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 decision making process. Strategies are selected based on
their ability to help Provident provide stable cash flow and distributions per
unit rather than to simply lock in a specific price per barrel of oil or cubic
foot of natural gas.

The result of Provident's hedging program in 2004 was an opportunity cost of
$68.9 million ($0.59 per unit).

Although Provident experienced opportunity costs in 2004,
Provident remains committed to its CPRMP. In 2004, 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
2004 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.

The following table summarizes the current Program as at December 31, 2004:

Oil - Canada

|Year | Product   | Volume | Terms | Effective Period                          
|---- | --------- | ------ | ----- | ------------------------------------------
|2005 | Light Oil | 2,750  | Bpd   | WTI US $26.07 per bbl (1)                 
|     |           | 500    | Bpd   | Costless collar US $26.00 - $30.10 per bbl

Oil - United States

|Year | Product   | Volume | Terms | Effective Period                         
|---- | --------- | ------ | ----- | -----------------------------------------
|2005 | Light Oil | 500    | Bpd   | Costless collar US$30.00 - $39.80 per bbl
|     |           | 500    | Bpd   | Costless collar US$30.00 - $39.50 per bbl
|     |           | 500    | Bpd   | Costless collar US$30.00 - $39.37 per bbl
|     |           | 500    | Bpd   | Costless collar US$30.00 - $40.00 per bbl
|     |           | 750    | Bpd   | Puts US $40.00 per bbl                   

Natural Gas

|Year | Product         | Volume | Terms | Effective Period                        
|---- | --------------- | ------ | ----- | ----------------------------------------
|2005 | Natural Gas (2) | 3,000  | Gjpd  | Cdn $5.90 per gj                        
|     |                 | 3,000  | Gjpd  | Costless collar Cdn $5.25 - $7.10 per gj
|     |                 | 2,000  | Gjpd  | Costless collar Cdn $5.50 - $7.29 per gj
|     |                 | 2,000  | Gjpd  | Costless collar Cdn $5.50 - $7.40 per gj
|     |                 | 1,000  | Gjpd  | Costless collar Cdn $5.50 - $7.60 per gj

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|Year | Product | Volume | Terms | Effective Period                        
|---- | ------- | ------ | ----- | ----------------------------------------
|     |         | 2,000  | Gjpd  | Costless collar Cdn $5.50 - $7.38 per gj
|     |         | 600    | Gjpd  | Cdn $5.39 per gj                        
|     |         | 2,000  | Gjpd  | Costless collar Cdn $5.50 - $6.88 per gj
|     |         | 5,000  | Gjpd  | Costless collar Cdn $6.00 - $9.10 per gj
|     |         | 5,000  | Gjpd  | Puts Cdn $6.50 per gj (1)               
|     |         | 5,000  | Gjpd  | Participating Swaps Cdn $6.00 per gj (3)

Notes: 
(1) Represents a number of transactions entered into over an extended period of
time. 
(2) Natural gas contracts are settled against AECO monthly index. 
(3) Provides a floor price while allowing percentage participation above strike
price.

> 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 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 2004, despite a bullish
commodity price environment, the 9 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 2004, the U.S./Canadian dollar exchange rate
averaged $0.767 compared to $0.708 in 2003. Given Canadian currency-denominated
2004 heavy oil hedges, Provident realized a $3.3 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.

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

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 35 percent of Provident's 2004 production and is Provident's
largest production area. Provident believes the strength of the West Central
Alberta region lies in its liquids-rich, long life natural gas reserves and
high-quality light crude oil. The acquisition of Olympia added production to
this core area during 2004.

During the fourth quarter, West Central Alberta production
included 47,705 mcfd (7,951 boed) of natural gas and 2,973 bpd of light/medium
oil and natural gas liquids. In 2004, Provident spent $10.2 million in the
region comprised of $6.5 million on drilling, $3.5 million on facilities with
the remainder on land and seismic expenditures. 2004 annual operating costs in
this area averaged $6.92 per boe.

In 2005, production is expected to average 39,623 mcfd (6,604
boed) natural gas and 2,529 bpd light/medium oil and natural gas liquids. With
total production anticipated to be 9,133 boed, West Central Alberta will remain
Provident's top-producing region. Capital expenditures are budgeted at
approximately $15 million, of which $4.7 million relates to drilling, $5.6
million on completions, equipment and tie-ins, $1.6 million on internal projects
and related items, and the remainder on facilities and land retention.

> Lloydminster

The Lloydminster region accounted for approximately 29
percent of Provident's 2004 production. Fourth quarter, 2004 production was
6,536 bpd of heavy oil and 5,030 mcfd (838 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. The acquisition of Viracocha and Olympia added production during 2004
for this core area.

Provident spent $10.2 million in the Lloydminster core area on drilling,
recompletions, equipping and seismic activity. Annual average operating costs
for Lloydminster averaged $9.36 per boe in 2004.

In 2005, Provident will allocate $10.9 million of capital to development and
optimization activities in the Lloydminster region, $6.9 million of this amount
will be spent on low-risk drilling opportunities, $1.1 on

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land acquisition and seismic evaluation, and $2.9 million on workovers and
facilities. Annual production is expected to be approximately 5,624 bpd of heavy
oil and 1,802 mcfd (300 boed) of natural gas.

> Southern Alberta

The Southern Alberta region accounted for approximately 24
percent of 2004 average production. The acquisition of Viracocha added to 2004
production for this core area. In the fourth quarter of 2004 natural gas
production averaged 27,967 mcfd (4,661 boed), while light/medium oil and NGLs
were 3,211 bpd. Provident spent $14.8 million in 2004 mainly comprised of $13.8
million on drilling, recompletions, and facility upgrades. Annual operating
costs in this area averaged $9.32 per boe.

In 2005, Provident intends to spend approximately $10.8
million in the Southern Alberta region, primarily on shallow natural gas-related
opportunities. Provident expects to spend $6.9 million on drilling-related
activities and the balance on facilities, land and seismic evaluation.
Production is expected to average 25,684 mcfd (4,281 boed) of natural gas and
2,967 bpd of light/medium oil and NGLs for 2005.

> Southwest Saskatchewan

Southwest Saskatchewan accounted for approximately 5 percent of Provident's
2004 production. The region was added to Provident's core operating areas
following the acquisition of Meota in 2002.

Fourth quarter production included 1,088 bpd of light/medium
oil and NGLs and 4,024 mcfd (671 boed) of natural gas. Production in this core
area has lower declines in the predominantly shallow natural-gas formations. In
2004, Provident spent $21.9 million in the region, $16.0 million on
drilling-related activities and facilities and $5.8 million on land acquisition,
retention and seismic evaluation. Annual operating costs in the area averaged
$11.76 per boe.

Due to Southwest Saskatchewan's significant low-risk infill
drilling and shallow natural gas development potential, Provident intends to
spend approximately $27.6 million, 40 percent of its capital budget, on shallow
gas development in 2005. The region's 2005 shallow gas capital program includes
$21.7 million on drilling and the remainder on land acquisition and seismic
evaluation. 2005 production is expected to average approximately 2,422 boed,
including 8,989 mcfd (1,498 boed) of natural gas and 924 bpd of light/medium oil
and NGLs.

> Southeast Saskatchewan

Provident's Southeast Saskatchewan region accounted for
approximately 7 percent of 2004 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 2004 production averaged 1,971 boed. Annual
operating costs averaged $8.22 per boe. In 2004, Provident spent $3.9 million in
the region, approximately $3.5 million of which was spent on drilling-related
activities, workovers and facilities and the remainder on land and seismic
expenditures.

Production is expected to average 1,859 boed in 2005. Provident intends to
spend approximately $3.2 million on capital projects, including $2.2 million to
be spent on drilling prospects.

> California

Beverley Hills East (West Pico Unit) is an oil and gas
property located onshore in Los Angeles County, California. West Pico was
discovered by Occidental Petroleum in 1964. A drillsite was built and
development commenced in 1966 with the West Pico Unit #1 well. Production peaked
in 1969 at 12,800 barrels per day of oil and 33,000 mcf per day of gas.
Cumulative production from the West Pico Unit is over 51 million barrels of oil
and 78 bcf of gas. Breitburn acquired the West Pico Unit from Occidental in 1993
and holds a 99% working interest. Current production from 26 producing wells is
approximately

- 39 -

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1,000 boe per day of light to medium crude oil (approximately
28 API) and associated gas. Remaining Breitburn interest proved plus probable
reserves were estimated by NSA to be 20.4 million barrels of oil equivalent.
Development potential includes expansion of the existing pressure maintenance
scheme (waterflood) as well as infill development wells.

Santa Fe Springs is a multi-zone oil property located onshore
in Los Angeles County, California. The Santa Fe Springs Field was discovered in
October 1919 by the Union Oil Company. Production peaked in 1928 at 300,000
barrels per day. The Santa Fe Springs Unit was formed by Mobil in 1969.
Cumulative production from the Santa Fe Springs Field is 625 million barrels of
oil. Breitburn acquired the Santa Fe Springs Unit from Texaco (successor to
Mobil) in 1999 and holds a 99.6% working interest. Current production from 89
producing wells is approximately 2,000 barrels per day of primarily light crude
oil (approximately 34 API). Remaining Breitburn interest proved plus probable
reserves were estimated by NSA to be 14.6 million barrels of oil equivalent.
Development potential includes expansion of waterflood operations, infill
drilling, recompletions and returning shut-in wells to production.

> Wyoming

Provident owns and operates eight fields in the Big Horn and
Wind River Basins with an average 99.4% working interest. Four main fields,
representing 85% of these acquired reserves were previously owned by a senior
U.S. oil and gas company. All the fields have been on production for 60 to 90
years and the current average annual decline rate is six percent. There are 135
active producing wells and 27 active injection wells.

The locations of fields where Provident is active are as
follows: (i) Rolff Lake and Sheldon Fields are located in Freemont County,
Wyoming; (ii) the majority of Black Mountain Field and Gebo Field are located in
Hot Springs County, Wyoming; (iii) Half Moon, North Sunshine, and West Oregon
Basin Fields are located in Park County, Wyoming; and (iv) Hidden Dome Field and
a small part of Black Mountain Field are located in Washakie County, Wyoming.

These fields have been actively developed since May 2003.
Much of the recent development has been in the Black Mountain and Gebo Fields
utilizing fracture stimulation and chemical treatments. Production has increased
from approximately 2,000 bpd to 2,370 bpd as of December 31, 2004.

> Reserves and Future Net Revenue

Provident's Canadian reserves were evaluated by McDaniel
effective December 31, 2004, in accordance with NI 51-101. Provident's United
States reserves were evaluated by NSA and by CGA effective December 31, 2004 in
accordance with NI 51-101. McDaniel, NSA and CGA are independent qualified
reserves evaluators appointed pursuant to NI 51-101. The McDaniel evaluation
report is dated February 25, 2005 with a preparation date of December 31, 2004.
The NSA evaluation report is dated March 2, 2005 with a preparation date of
December 31, 2004 and the CGA evaluation report is dated March 1, 2005 with a
preparation date of March 1, 2005.

The following is a summary, as at December 31, 2004 of the
crude oil, NGLs and natural gas reserves attributed by such reports and the
estimated net present values of future net revenues associated with such
reserves, based on constant price and cost assumptions and on forecast price and
cost assumptions. The tables summarize the data contained in the evaluations and
as a result may contain slightly different numbers than the evaluations due to
rounding. The pricing used in the constant price and in the forecast 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 does not necessarily represent the fair market value of
Provident's reserves. There is no assurance that the

- 40 -

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forecast price and cost assumptions contained in the reserve
reports will be attained and variances could be material. Other assumptions and
qualifications relating to costs and other matters are included in the reserves
reports. The recovery and reserves estimates on the properties described herein
are estimates only. Because the reserves data are based on judgments regarding
future events, actual results will vary and variations may be material.

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

|                         | CONSOLIDATED        
|------------------------ | --------------------
|                         | Light and Medium Oil
|                         | Gross(1)            
|                         | (Mbbl)              
|Proved Developed         |                     
|                         | 48,752              
|Producing(2)(6)          |                     
|Proved Developed         |                     
|                         | 4,708               
|Non-Producing(2)(7)      |                     
|Proved Undeveloped(2)(8) | 9,220               
|Total Proved(2)          | 62,680              
|                         |                     
|                         |                     
|                         | CANADA              
|                         | Light and Medium Oil
|                         | Gross(1)            
|                         | (Mbbl)              
|Proved Developed         |                     
|                         | 14,997              
|Producing(2)(6)          |                     
|Proved Developed         |                     
|                         | 508                 
|Non-Producing(2)(7)      |                     
|Proved Undeveloped(2)(8) | 253                 
|Total Proved(2)          | 15,759              
|                         |                     
|                         | UNITED STATES       
|                         | Light and Medium Oil
|                         | Gross(1)            
|                         | (Mbbl)              
|Proved Developed         |                     
|                         | 33,755              
|Producing(2)(6)          |                     
|Proved Developed         |                     
|                         | 4,200               
|Non-Producing(2)(7)      |                     
|Proved Undeveloped(2)(8) | 8,966               
|Total Proved(2)          | 46,922              

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

CONSOLIDATED

|                                     | Before Income Taxes | After
    Income Taxes(11)
|------------------------------------ | ------------------- | --------------------------
|                                     | Discounted At       | Discounted At             
|                                     | 0%                  | 10%                       
|                                     | (MM$)               | (MM$)                     
|Proved Developed Producing(2)(6)     | 1,470               | 869                       
|Proved Developed Non-Producing(2)(7) | 173                 | 84                        
|Proved Undeveloped(2)(8)             | 405                 | 172                       
|Total Proved(2)                      | 2,049               | 1,125                     

- 41 -

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CANADA

|                                     | Before Income Taxes | After
    Income Taxes(11)
|------------------------------------ | ------------------- | --------------------------
|                                     | Discounted At       | Discounted At             
|                                     | 0%                  | 10%                       
|                                     | (MM$)               | (MM$)                     
|Proved Developed Producing(2)(6)     | 790                 | 560                       
|Proved Developed Non-Producing(2)(7) | 66                  | 40                        
|Proved Undeveloped(2)(8)             | 35                  | 20                        
|Total Proved(2)                      | 892                 | 620                       

UNITED STATES

|                                     | Before Income
    Taxes | After Income Taxes(11)
|------------------------------------ | ----------------------- | ----------------------
|                                     | Discounted At           | Discounted At         
|                                     | 0%                      | 10%                   
|                                     | (MM$)                   | (MM$)                 
|Proved Developed Producing(2)(6)     | 680                     | 309                   
|                                     |                         |                       
|Proved Developed Non-Producing(2)(7) | 107                     | 44                    
|                                     |                         |                       
|Proved Undeveloped(2)(8)             | 370                     | 152                   
|Total Proved(2)                      | 1,157                   | 505                   

U.S. taxes were calculated by Provident using the reserve
forecast for revenue, royalties and operating expenses to determine operating
cash flow. Forecast capital expenditures, administration expenses and interest
expenses were then deducted to calculate taxable income. Current federal, state
and withholding tax rates were then applied to determine a tax expense for each
year of the reserves forecast. The tax expenses were provided to the U.S.
evaluators and applied to the future cash flows.

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

CONSOLIDATED

|                |         |           |           |             |                 | Future        |           | Future       
|--------------- | ------- | --------- | --------- | ----------- | --------------- | ------------- | --------- | -------------
|                |         |           |           |             | Abandonment     | Net Revenue   |           | Net          
|                |         |           | Operating | Development | and Reclamation | Before Income | Income    | Revenue After
|                | Revenue | Royalties | Costs     | Costs       | Costs           | Taxes         | Taxes(11) | Income Taxes 
|                | (MM$)   | (MM$)     | (MM$)     | (MM$)       | (MM$)           | (MM$)         | (MM$)     | (MM$)        
|Total Proved(2) | 4,418   | 655       | 1,404     | 216         | 94              | 2,049         | 306       | 1,742        

CANADA

|                |         |           |           |             |                 | Future        |           | Future       
|--------------- | ------- | --------- | --------- | ----------- | --------------- | ------------- | --------- | -------------
|                |         |           |           |             | Abandonment     | Net Revenue   |           | Net          
|                |         |           | Operating | Development | and Reclamation | Before Income | Income    | Revenue After
|                | Revenue | Royalties | Costs     | Costs       | Costs           | Taxes         | Taxes(11) | Income Taxes 
|                | (MM$)   | (MM$)     | (MM$)     | (MM$)       | (MM$)           | (MM$)         | (MM$)     | (MM$)        
|Total Proved(2) | 1,785   | 311       | 465       | 39          | 78              | 892           | 0         | 892          

UNITED STATES

|                |         |           |           |             |                 | Future        |           | Future       
|--------------- | ------- | --------- | --------- | ----------- | --------------- | ------------- | --------- | -------------
|                |         |           |           |             | Abandonment     | Net Revenue   |           | Net          
|                |         |           | Operating | Development | and Reclamation | Before Income | Income    | Revenue After
|                | Revenue | Royalties | Costs     | Costs       | Costs           | Taxes         | Taxes(11) | Income Taxes 
|                | (MM$)   | (MM$)     | (MM$)     | (MM$)       | (MM$)           | (MM$)         | (MM$)     | (MM$)        
|Total Proved(2) | 2,633   | 344       | 939       | 176         | 16              | 1,157         | 306       | 850          

- 42 -

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TOTAL COMPANY

FUTURE NET REVENUE BY PRODUCTION GROUP 
BASED UPON CONSTANT PRICES AND COSTS(9)(12)

CONSOLIDATED

|                |                                       | Future Net Revenue Before
    Income
|--------------- | ------------------------------------- | ------------------------------------
|                |                                       | Taxes (Discounted at 10%/Year)      
|                | Production Group                      | (M$)                                
|Total Proved(2) | Light and medium crude oil            | 651,422                             
|                | Heavy oil                             | 39,565                              
|                | Associated and non-associated
    gas | 432,001                             

CANADA

|                |                                       | Future Net Revenue Before
    Income
|--------------- | ------------------------------------- | ------------------------------------
|                |                                       | Taxes (Discounted at 10%/Year)      
|                | Production Group                      | (M$)                                
|Total Proved(2) | Light and medium crude oil            | 173,743                             
|                | Heavy oil                             | 12,360                              
|                | Associated and non-associated
    gas | 432,001                             

UNITED STATES

|                |                                       | Future Net Revenue Before
    Income
|--------------- | ------------------------------------- | ------------------------------------
|                |                                       | Taxes (Discounted at 10%/Year)      
|                | Production Group                      | (M$)                                
|Total Proved(2) | Light and medium crude oil            | 477,679                             
|                | Heavy oil                             | 27,205                              
|                | Associated and non-associated
    gas | 0                                   

OIL AND GAS RESERVES 
BASED ON FORECAST PRICES AND COSTS

CONSOLIDATED

|                                     | Light
    and Medium |           |             |         |          | Natural Gas
|------------------------------------ | -------------------- | --------- | ----------- | ------- | -------- | -----------
|                                     | Oil                  | Heavy Oil | Natural Gas | Liquids
|                                     | Gross(1)             | Net(1)    | Gross(1)    | Net(1)  | Gross(1) | Net(1)     
|                                     | (Mbbl)               | (Mbbl)    | (Mbbl)      | (Mbbl)  | (MMcf)   | (MMcf)     
|Proved Developed Producing(2)(6)     | 43,393               | 39,053    | 5,158       | 4,532   | 130,972  | 109,913    
|Proved Developed Non-Producing(2)(7) | 4,229                | 3,870     | 690         | 580     | 21,421   | 17,434     
|Proved Undeveloped(2)(8)             | 8,630                | 7,153     | 4,787       | 4,333   | 17,924   | 15,377     
|Total Proved(2)                      | 56,252               | 50,075    | 10,634      | 9,445   | 170,318  | 142,724    
|Total Probable(3)                    | 13,791               | 12,049    | 7,231       | 6,541   | 52,026   | 43,826     
|Total Proved Plus Probable(2)(3)     | 70,043               | 62,124    | 17,865      | 15,986  | 222,343  | 186,550    

CANADA

|                                     | Light
    and Medium |           |             |                     |          |         |         
|------------------------------------ | -------------------- | --------- | ----------- | ------------------- | -------- | ------- | --------
|                                     | Oil                  | Heavy Oil | Natural Gas | Natural Gas Liquids
|                                     | Gross(1)             | Net(1)    | Gross(1)    | Net(1)              | Gross(1) | Net(1)  | Gross(1)
|                                     | (Mbbl)               | (Mbbl)    | (Mbbl)      | (Mbbl)              | (MMcf)   | (MMcf)  | (Mbbl)  
|Proved Developed Producing(2)(6)     | 15,258               | 13,010    | 3,509       | 3,022               | 123,228  | 103,312 | 2,828   
|Proved Developed Non-Producing(2)(7) | 498                  | 437       | 683         | 573                 | 20,550   | 16,682  | 185     
|Proved Undeveloped(2)(8)             | 255                  | 221       | 2,817       | 2,521               | 7,264    | 6,611   | 131     
|Total Proved(2)                      | 16,011               | 13,668    | 7,008       | 6,117               | 151,042  | 126,605 | 3,144   
|Total Probable(3)                    | 4,021                | 3,437     | 4,315       | 3,860               | 44,163   | 37,303  | 994     
|Total Proved Plus Probable(2)(3)     | 20,032               | 17,105    | 11,323      | 9,977               | 195,204  | 163,908 | 4,137   

- 43 -

---



UNITED STATES

|                                     | Light and Medium |           |             |                     |          |        |         
|------------------------------------ | ---------------- | --------- | ----------- | ------------------- | -------- | ------ | --------
|                                     | Oil              | Heavy Oil | Natural Gas | Natural Gas Liquids
|                                     | Gross(1)         | Net(1)    | Gross(1)    | Net(1)              | Gross(1) | Net(1) | Gross(1)
|                                     | (Mbbl)           | (Mbbl)    | (Mbbl)      | (Mbbl)              | (MMcf)   | (MMcf) | (Mbbl)  
|Proved Developed Producing(2)(6)     | 28,135           | 26,043    | 1,649       | 1,510               | 7,744    | 6,601  | 74      
|Proved Developed Non-Producing(2)(7) | 3,731            | 3,433     | 7           | 7                   | 872      | 752    | 0       
|Proved Undeveloped(2)(8)             | 8,375            | 6,931     | 1,970       | 1,812               | 10,660   | 8,766  | 606     
|Total Proved(2)                      | 40,241           | 36,407    | 3,626       | 3,329               | 19,276   | 16,119 | 681     
|Total Probable(3)                    | 9,770            | 8,611     | 2,916       | 2,681               | 7,863    | 6,523  | 371     
|Total Proved Plus Probable(2)(3)     | 50,011           | 45,019    | 6,542       | 6,009               | 27,139   | 22,642 | 1,052   

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

CONSOLIDATED

|                                     | Before Deducting Income Taxes | After Deducting
    Income Taxes(11)
|------------------------------------ | ----------------------------- | ------------------------------------
|                                     | Discounted At                 | Discounted At                       
|                                     | 0%                            | 5%                                  
|                                     | (MM$)                         | (MM$)                               
|Proved Developed Producing(2)(6)     | 1,124                         | 912                                 
|Proved Developed Non-Producing(2)(7) | 125                           | 86                                  
|Proved Undeveloped(2)(8)             | 301                           | 191                                 
|Total Proved(2)                      | 1,549                         | 1,189                               
|Total Probable(3)                    | 607                           | 377                                 
|Total Proved Plus Probable(2)(3)     | 2,156                         | 1,567                               

CANADA

|                                     | Before Deducting
    Income Taxes | After Deducting
    Income Taxes(11)
|------------------------------------ | --------------------------------- | ------------------------------------
|                                     | Discounted At                     | Discounted At                       
|                                     | 0%                                | 5%                                  
|                                     | (MM$)                             | (MM$)                               
|Proved Developed Producing(2)(6)     | 788                               | 664                                 
|Proved Developed Non-Producing(2)(7) | 58                                | 45                                  
|Proved Undeveloped(2)(8)             | 51                                | 41                                  
|Total Proved(2)                      | 897                               | 750                                 
|Total Probable(3)                    | 295                               | 206                                 
|Total Proved Plus Probable(2)(3)     | 1,192                             | 956                                 

UNITED STATES

|                                     | Before Deducting
    Income Taxes | After Deducting
    Income Taxes(11)
|------------------------------------ | --------------------------------- | ------------------------------------
|                                     | Discounted At                     | Discounted At                       
|                                     | 0%                                | 5%                                  
|                                     | (MM$)                             | (MM$)                               
|Proved Developed Producing(2)(6)     | 336                               | 248                                 
|Proved Developed Non-Producing(2)(7) | 67                                | 41                                  
|Proved Undeveloped(2)(8)             | 250                               | 150                                 
|Total Proved(2)                      | 653                               | 440                                 
|Total Probable(3)                    | 312                               | 172                                 
|Total Proved Plus Probable(2)(3)     | 964                               | 611                                 

- 44 -

---



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

CONSOLIDATED

|                                 |         |           |           |             | Abandonment | Future        |           | Future       
|-------------------------------- | ------- | --------- | --------- | ----------- | ----------- | ------------- | --------- | -------------
|                                 |         |           |           |             | and         | Net Revenue   |           | Net          
|                                 |         |           | Operating | Development | Reclamation | Before Income | Income    | Revenue After
|                                 | Revenue | Royalties | Costs     | Costs       | Costs       | Taxes         | Taxes(11) | Income Taxes 
|                                 | (MM$)   | (MM$)     | (MM$)     | (MM$)       | (MM$)       | (MM$)         | (MM$)     | (MM$)        
|Total Proved(2)                  | 3,926   | 585       | 1,442     | 233         | 117         | 1,549         | 124       | 1,425        
|Total Proved Plus Probable(2)(3) | 5,151   | 772       | 1,811     | 291         | 121         | 2,156         | 203       | 1,953        

CANADA

|                                 |         |           |           |             | Abandonment | Future        |           | Future       
|-------------------------------- | ------- | --------- | --------- | ----------- | ----------- | ------------- | --------- | -------------
|                                 |         |           |           |             | and         | Net Revenue   |           | Net          
|                                 |         |           | Operating | Development | Reclamation | Before Income | Income    | Revenue After
|                                 | Revenue | Royalties | Costs     | Costs       | Costs       | Taxes         | Taxes(11) | Income Taxes 
|                                 | (MM$)   | (MM$)     | (MM$)     | (MM$)       | (MM$)       | (MM$)         | (MM$)     | (MM$)        
|Total Proved(2)                  | 1,893   | 325       | 538       | 41          | 93          | 897           | 0         | 897          
|Total Proved Plus Probable(2)(3) | 2,488   | 422       | 714       | 64          | 97          | 1,192         | 0         | 1,192        

UNITED STATES

|                                 |         |           |           |             | Abandonment | Future        |           | Future       
|-------------------------------- | ------- | --------- | --------- | ----------- | ----------- | ------------- | --------- | -------------
|                                 |         |           |           |             | and         | Net Revenue   |           | Net          
|                                 |         |           | Operating | Development | Reclamation | Before Income | Income    | Revenue After
|                                 | Revenue | Royalties | Costs     | Costs       | Costs       | Taxes         | Taxes(11) | Income Taxes 
|                                 | (MM$)   | (MM$)     | (MM$)     | (MM$)       | (MM$)       | (MM$)         | (MM$)     | (MM$)        
|Total Proved(2)                  | 2,033   | 260       | 904       | 192         | 24          | 653           | 124       | 529          
|Total Proved Plus Probable(2)(3) | 2,663   | 350       | 1,097     | 227         | 24          | 964           | 203       | 761          

FUTURE NET REVENUE BY PRODUCTION GROUP 
BASED ON FORECAST PRICES AND COSTS(10)(12)

CONSOLIDATED

|                |                                       | Future Net Revenue Before
    Income
|--------------- | ------------------------------------- | ------------------------------------
|                |                                       | Taxes (Discounted at 10%/Year)      
|                | Production Group                      | (M$)                                
|Total Proved(2) | Light and medium crude oil            | 510,401                             
|                | Heavy oil                             | 73,262                              
|                | Associated and non-associated
    gas | 392,468                             

CANADA

|                |                                       | Future Net
    Revenue Before Income
|--------------- | ------------------------------------- | ------------------------------------
|                |                                       | Taxes (Discounted
    at 10%/Year)  
|                | Production Group                      | (M$)                                
|Total Proved(2) | Light and medium crude oil            | 202,105                             
|                | Heavy oil                             | 56,087                              
|                | Associated and
    non-associated gas | 392,468                             

- 45 -

---



UNITED STATES

|                |                                       | Future Net
    Revenue Before Income
|--------------- | ------------------------------------- | ------------------------------------
|                |                                       | Taxes (Discounted
    at 10%/Year)  
|                | Production Group                      | (M$)                                
|Total Proved(2) | Light and medium crude oil            | 308,296                             
|                | Heavy oil                             | 17,175                              
|                | Associated and
    non-associated gas | 0                                   

Reconciliation of Changes in Reserves and Future Net Revenue

The following tables set 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, 2004 against such
reserves as at December 31, 2003 based on the price and cost assumptions set
forth in note 10.

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

CONSOLIDATED

|                     | Light & Medium Oil & NGL | Heavy Oil | Associated & Non Associated Gas
|-------------------- | ------------------------ | --------- | -------------------------------
|                     | Net                      |           |                                
|                     |                          |           | Proved                         
|                     |                          | Net       | Plus                           
|                     | Net Proved               | Probable  | Probable                       
|                     | (Mbbl)                   | (Mbbl)    | (Mbbl)                         
|                     |                          |           |                                
|At December 31, 2003 | 11,774.0                 | 3,140.7   | 14,914.7                       
|Extensions           | 454.3                    | 74.5      | 528.8                          
|Improved Recovery    | 0.0                      | 0.0       | 0.0                            
|Technical Revisions  | 930.8                    | -648.3    | 282.5                          
|Discoveries          | 17.1                     | 3.4       | 20.5                           
|Acquisitions         | 43,187.5                 | 10,296.3  | 53,483.8                       
|Dispositions         | -154.3                   | -20.5     | -174.8                         
|Economic Factors     | 458.7                    | 280.9     | 739.6                          
|Production           | -3,585.1                 | 0.0       | -3,585.1                       
|At December 31, 2004 | 53,082.9                 | 13,127.0  | 66,210.1                       
|                     |                          |           |                                

CANADA

|                     | Light & Medium Oil & NGL | Heavy Oil | Associated & Non Associated Gas
|-------------------- | ------------------------ | --------- | -------------------------------
|                     |                          |           | Net                            
|                     |                          |           | Proved                         
|                     |                          | Net       | Plus                           
|                     | Net Proved               | Probable  | Probable                       
|                     | (Mbbl)                   | (Mbbl)    | (Mbbl)                         
|                     |                          |           |                                
|At December 31, 2003 | 11,774.0                 | 3,140.7   | 14,914.7                       
|Extensions           | 454.3                    | 74.5      | 528.8                          
|Improved Recovery    | 0.0                      | 0.0       | 0.0                            
|Technical Revisions  | 930.8                    | -648.3    | 282.5                          
|Discoveries          | 17.1                     | 3.4       | 20.5                           
|Acquisitions         | 5,508.0                  | 1,379.5   | 6,887.5                        
|Dispositions         | -154.3                   | -20.5     | -174.8                         
|Economic Factors     | 458.7                    | 280.9     | 739.6                          
|Production           | -2,875.5                 | 0.0       | -2,875.5                       
|At December 31, 2004 | 16,113.1                 | 4,210.3   | 20,323.4                       

UNITED STATES

|                     | Light & Medium Oil & NGL | Heavy Oil | Associated & Non Associated Gas
|-------------------- | ------------------------ | --------- | -------------------------------
|                     |                          |           | Net                            
|                     |                          |           | Proved                         
|                     |                          | Net       | Plus                           
|                     | Net Proved               | Probable  | Probable                       
|                     | (Mbbl)                   | (Mbbl)    | (Mbbl)                         
|                     |                          |           |                                
|At December 31, 2003 | 0                        | 0         | 0                              
|Extensions           | 0                        | 0         | 0                              

- 46 -

---



|                     |                          |           |                                 |         |          |          |          |          |           
|-------------------- | ------------------------ | --------- | ------------------------------- | ------- | -------- | -------- | -------- | -------- | ----------
|                     | Light & Medium Oil & NGL | Heavy Oil | Associated & Non Associated Gas
|                     |                          |           | Net                             |         |          | Net      |          |          |           
|                     |                          |           | Proved                          |         |          | Proved   |          |          | Net Proved
|                     |                          | Net       | Plus                            | Net     | Net      | Plus     | Net      | Net      | Plus      
|                     | Net Proved               | Probable  | Probable                        | Proved  | Probable | Probable | Proved   | Probable | Probable  
|                     | (Mbbl)                   | (Mbbl)    | (Mbbl)                          | (Mbbl)  | (Mbbl)   | (Mbbl)   | (MMcf)   | (MMcf)   | (MMcf)    
|Improved Recovery    | 0                        | 0         | 0                               | 0       | 0        | 0        | 0        | 0        | 0         
|Technical Revisions  | 0                        | 0         | 0                               | 0       | 0        | 0        | 0        | 0        | 0         
|Discoveries          | 0                        | 0         | 0                               | 0       | 0        | 0        | 0        | 0        | 0         
|Acquisitions         | 37,679.5                 | 8,916.8   | 46,596.3                        | 3,333.9 | 2,680.7  | 6,014.6  | 16,384.4 | 6,523.2  | 22,907.6  
|Dispositions         | 0                        | 0         | 0                               | 0       | 0        | 0        | 0        | 0        | 0         
|Economic Factors     | 0                        | 0         | 0                               | 0       | 0        | 0        | 0        | 0        | 0         
|Production           | -709.6                   | 0         | -709.6                          | -5.3    | 0        | -5.3     | -265.4   | 0        | -265.4    
|At December 31, 2004 | 36,969.8                 | 8,916.8   | 45,886.7                        | 3,328.5 | 2,680.7  | 6,009.2  | 16,119.0 | 6,523.2  | 22,642.2  
|                     |                          |           |                                 |         |          |          |          |          |           

The following tables set forth changes between future net revenue estimates
attributable to net proved reserves as at December 31, 2004 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)

CONSOLIDATED

|                                                                                       | (M$)     
|-------------------------------------------------------------------------------------- | ---------
|                                                                                       |          
|Estimated Future Net Revenue at
    December 31, 2003                                  | 451,904  
|Sales and Transfers of Oil and
    Gas Produced, Net of Production Costs and Royalties | (250,491)
|Net Change in Prices, Production
    Costs and Royalties Related to Future Production  | 121,462  
|Changes in Previously Estimated
    Future Development Costs                           | (52,100) 
|Changes in Estimated Future
    Development Costs                                      | (18,400) 
|Extensions and Improved Recovery                                                       | 44,519   
|Discoveries                                                                            | 1,262    
|Acquisitions of Reserves                                                               | 556,429  
|Dispositions of Reserves                                                               | (5,566)  
|Net Change Resulting from
    Revisions in Quantity Estimates                          | 91,677   
|Accretion of Discount                                                                  | 32,830   
|Net Change in Income Taxes                                                             | 0        
|Estimated After Tax Future Net
    Revenue at December 31, 2004                        | 973,526  

CANADA

|                                                                                       | (M$)     
|-------------------------------------------------------------------------------------- | ---------
|                                                                                       |          
|Estimated Future Net Revenue at
    December 31, 2003                                  | 451,904  
|Sales and Transfers of Oil and
    Gas Produced, Net of Production Costs and Royalties | (224,842)
|Net Change in Prices, Production
    Costs and Royalties Related to Future Production  | 121,462  
|Changes in Previously Estimated
    Future Development Costs                           | (52,100) 
|Changes in Estimated Future
    Development Costs                                      | (18,400) 
|Extensions and Improved Recovery                                                       | 44,519   
|Discoveries                                                                            | 1,262    
|Acquisitions of Reserves                                                               | 177,546  
|Dispositions of Reserves                                                               | (5,566)  
|Net Change Resulting from
    Revisions in Quantity Estimates                          | 91,677   
|Accretion of Discount                                                                  | 32,830   
|Net Change in Income Taxes                                                             | 0        
|Estimated After Tax Future Net
    Revenue at December 31, 2004                        | 620,293  

- 47 -

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UNITED STATES

|                                                                                       | (M$)    
|-------------------------------------------------------------------------------------- | --------
|                                                                                       |         
|Estimated Future Net Revenue at December 31,
    2003                                  | 0       
|Sales and Transfers of Oil and Gas Produced,
    Net of Production Costs and Royalties | (25,649)
|Net Change in Prices, Production Costs and
    Royalties Related to Future Production  | -       
|Changes in Previously Estimated Future
    Development Costs                           | -       
|Changes in Estimated Future Development Costs                                          | -       
|Extensions and Improved Recovery                                                       | -       
|Discoveries                                                                            | -       
|Acquisitions of Reserves                                                               | 378,883 
|Dispositions of Reserves                                                               | -       
|Net Change Resulting from Revisions in
    Quantity Estimates                          | -       
|Accretion of Discount                                                                  | -       
|Net Change in Income Taxes                                                             | -       
|Estimated After Tax Future Net Revenue at
    December 31, 2004                        | 353,233 

Notes:

1. "Gross Reserves" are Provident's working interest (operated or
  non-operated) share before deducting royalties and without including any
  royalty interests of Provident. "Net Reserves" are Provident's working
  interest (operated or non-operated) share after deduction of royalty
  obligations, plus Provident's royalty interests in reserves. Reserves and
  values reported are based on 100% of the interests of Breitburn L.P. in the
  U.S. properties as at December 31, 2004. Provident indirectly holds
  approximately 94.2% of the outstanding partnership interests of Breitburn L.P.
  with the remaining approximately 5.8% of the partnership interests held by
  Breitburn's co-founders and co-chief executive officers.
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 known accumulations where a significant expenditure (for
  example, when compared to the cost of drilling a well) is required to render
  them capable of production. They must fully meet the requirements of the
  reserves classification (proved, probable, possible) to which they are
  assigned.
9. The product prices used in the constant price and cost
  evaluations, from McDaniel & Associates December 31, 2004 Constant Price
  Schedule, were as follows: Nymex West Texas Intermediate Crude $U.S.
  43.45/bbl; Edmonton Light Crude $Cdn $46.51/bbl; Bow River Medium Crude $Cdn
  25.03/bbl; Hardisty Heavy Crude $Cdn 18.03/bbl; Cromer Medium Crude $Cdn
  38.46/bbl; Alberta Average Natural Gas $Cdn 6.62/mcf; Natural Gas Liquids Mix
  $Cdn 35.30/bbl.
10. The pricing assumptions used with respect to net present
  values of future net revenue (forecast) as well as the inflation rates used
  for operating and capital costs are set forth below in the McDaniel &
  Associates Consultants Ltd. Summary of Price Forecasts.
11. After tax forecasts are equal to before tax forecasts for
  Canadian properties as Provident is a royalty trust. After tax forecasts for
  the United States properties are based on U.S federal, state and withholding
  taxes.
12. Future Net Revenue by production group does not equal Total
  Future Net Revenue in other tables due to the effects of hedging, ARTC and
  facility income/expenses.

McDaniel & Associates Consultants Ltd. 
Summary of Price Forecasts 
January 1, 2005

|     |           | Edmonton  | Sask. Cromer | Alberta   | Alberta   |          |           |              
|---- | --------- | --------- | ------------ | --------- | --------- | -------- | --------- | -------------
|     | WTI       | Light     | Medium       | Heavy     | AECO Spot | Edmonton |           | US/Cdn       
|     | Crude Oil | Crude Oil | Crude Oil    | Crude Oil | Gas Price | NGL Mix  | Inflation | Exchange Rate
|Year | $US/bbl   | $Cdn/bbl  | $Cdn/bbl     | $Cdn/bbl  | $Cdn/GJ   | $Cdn/bbl | %         | $US/$Cdn     
|2005 | 42.00     | 49.60     | 43.50        | 29.40     | 6.45      | 37.20    | 2.0       | 0.830        
|2006 | 39.50     | 46.60     | 40.90        | 29.90     | 6.20      | 35.10    | 2.0       | 0.830        
|2007 | 37.00     | 43.50     | 38.20        | 27.90     | 6.05      | 33.00    | 2.0       | 0.830        
|2008 | 35.00     | 41.10     | 36.00        | 26.30     | 5.80      | 31.20    | 2.0       | 0.830        
|2009 | 34.50     | 40.50     | 35.50        | 25.90     | 5.70      | 30.80    | 2.0       | 0.830        
|     |           |           |              |           |           |          |           |              
|2010 | 34.30     | 40.20     | 35.30        | 25.80     | 5.60      | 30.50    | 2.0       | 0.830        
|2011 | 35.00     | 41.00     | 36.00        | 26.30     | 5.80      | 31.10    | 2.0       | 0.830        

- 48 -

---



|           |           | Edmonton  | Sask. Cromer | Alberta   | Alberta   |          |           |              
|---------- | --------- | --------- | ------------ | --------- | --------- | -------- | --------- | -------------
|           | WTI       | Light     | Medium       | Heavy     | AECO Spot | Edmonton |           | US/Cdn       
|           | Crude Oil | Crude Oil | Crude Oil    | Crude Oil | Gas Price | NGL Mix  | Inflation | Exchange Rate
|Year       | $US/bbl   | $Cdn/bbl  | $Cdn/bbl     | $Cdn/bbl  | $Cdn/GJ   | $Cdn/bbl | %         | $US/$Cdn     
|2012       | 35.70     | 41.90     | 36.70        | 26.80     | 5.90      | 31.80    | 2.0       | 0.830        
|2013       | 36.40     | 42.70     | 37.40        | 27.30     | 5.95      | 32.40    | 2.0       | 0.830        
|2014       | 37.10     | 43.50     | 38.10        | 27.90     | 6.05      | 33.00    | 2.0       | 0.830        
|           |           |           |              |           |           |          |           |              
|2015       | 37.80     | 44.30     | 38.90        | 28.40     | 6.20      | 33.60    | 2.0       | 0.830        
|2016       | 38.60     | 45.30     | 39.70        | 29.00     | 6.35      | 34.40    | 2.0       | 0.830        
|2017       | 39.40     | 46.20     | 40.50        | 29.60     | 6.45      | 35.10    | 2.0       | 0.830        
|2018       | 40.20     | 47.10     | 41.30        | 30.20     | 6.65      | 35.80    | 2.0       | 0.830        
|2019       | 41.00     | 48.10     | 42.20        | 30.80     | 6.75      | 36.50    | 2.0       | 0.830        
|           |           |           |              |           |           |          |           |              
|2020       | 41.80     | 49.00     | 43.00        | 31.40     | 6.85      | 37.20    | 2.0       | 0.830        
|2021       | 42.60     | 50.00     | 43.80        | 32.00     | 6.95      | 37.90    | 2.0       | 0.830        
|2022       | 43.50     | 51.00     | 44.70        | 32.70     | 7.15      | 38.80    | 2.0       | 0.830        
|2023       | 44.40     | 52.10     | 45.60        | 33.30     | 7.30      | 39.60    | 2.0       | 0.830        
|2024       | 45.30     | 53.10     | 46.60        | 34.00     | 7.50      | 40.40    | 2.0       | 0.830        
|           |           |           |              |           |           |          |           |              
|Thereafter | 45.30     | 53.10     | 46.60        | 34.00     | 7.50      | 40.40    | 0.0       | 0.830        

Undeveloped Reserves

The following tables set forth the volumes of net proved and
probable undeveloped reserves that were attributed for each product type for the
most recent four financial years, based upon forecast prices and costs.
Provident was established as a trust in 2001. Proved and probable undeveloped
reserves were attributed in accordance with NI 51-101.

|Proved Undeveloped   | Light and Medium Oil | Heavy Oil | Natural Gas | Natural Gas Liquids
|-------------------- | -------------------- | --------- | ----------- | -------------------
|                     | (Mbbl)               | (Mbbl)    | (MMcf)      | (Mbbl)             
|2001(1)              | 230                  | 4,287     | 4,924       | 122                
|2002                 | 330                  | 3,775     | 3,495       | 48                 
|2003                 | 155                  | 2,745     | 1,774       | 39                 
|2004 Consolidated    | 7,153                | 4,333     | 15,377      | 603                
|                     |                      |           |             |                    
|2004 Canada          | 221                  | 2,521     | 6,611       | 104                
|2004 U.S.(2)         | 6,931                | 1,812     | 8,766       | 499                
|                     |                      |           |             |                    
|                     |                      |           |             |                    
|Probable Undeveloped | Light and Medium Oil | Heavy Oil | Natural Gas | Natural Gas Liquids
|                     | (Mbbl)               | (Mbbl)    | (MMcf)      | (Mbbl)             
|2001(1)              | 512                  | 3,850     | 5,873       | 209                
|2002                 | 121                  | 3,439     | 2,382       | 42                 
|2003                 | 228                  | 3,181     | 821         | 12                 
|2004                 | 2,338                | 5,121     | 6,666       | 243                
|                     |                      |           |             |                    
|2004 Canada          | 226                  | 2,440     | 3,025       | 92                 
|2004 U.S.(2)         | 2,112                | 2,681     | 3,640       | 151                

Notes:

1. Provident was established as a trust in 2001. 
2. U.S. properties were acquired in 2004.

Proved and Probable Undeveloped reserves for the Canadian
Properties consist primarily of heavy oil development wells in the Lloydminster
area of Alberta and Saskatchewan plus shallow gas wells at Atlee Buffalo in S.E.
Alberta and at Senate/Vidora in S.W. Saskatchewan.

In the U.S., Beverly Hills East Undeveloped reserves have been assigned to
expansion of the existing pressure maintenance scheme (waterflood) as well as to
infill development wells, which are scheduled to

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be drilled over the next two years. Proved and Probable
Undeveloped heavy oil reserves have also been assigned to expansion of the Stern
zone waterflood at the East Coyote field in Orange County, California. Phase one
of this waterflood commenced in 2004 and phase two is scheduled to commence in
2006.

Undeveloped reserves are scheduled to be developed over a two to four year
time frame to replace naturally occurring production declines.

Future Development Costs

The following tables set out the future development costs for undeveloped
reserves.

CONSOLIDATED

|                                      | Total Proved        | Total Proved        | Total Proved Plus    
|------------------------------------- | ------------------- | ------------------- | ---------------------
|                                      | Estimated Using     | Estimated Using     | Probable Estimated   
|                                      | Constant Prices and | Forecast Prices and | Using Forecast Prices
|                                      | Costs               | Costs               | and Costs            
|                                      | (M$)                | (M$)                | (M$)                 
|2005                                  | 50,575              | 51,074              | 60,371               
|2006                                  | 30,367              | 31,152              | 45,409               
|2007                                  | 12,368              | 12,923              | 19,291               
|2008                                  | 7,745               | 8,195               | 14,192               
|2009                                  | 5,629               | 5,953               | 11,272               
|Total for all years undiscounted      | 215,586             | 232,739             | 290,806              
|Total for all years discounted at 10% | 120,093             | 125,649             | 162,497              

CANADA

|                                      | Total Proved        | Total Proved        | Total Proved Plus    
|------------------------------------- | ------------------- | ------------------- | ---------------------
|                                      | Estimated Using     | Estimated Using     | Probable Estimated   
|                                      | Constant Prices and | Forecast Prices and | Using Forecast Prices
|                                      | Costs               | Costs               | and Costs            
|                                      | (M$)                | (M$)                | (M$)                 
|2005                                  | 21,500              | 21,700              | 30,600               
|2006                                  | 8,300               | 8,600               | 15,800               
|2007                                  | 4,900               | 5,200               | 9,200                
|2008                                  | 2,700               | 2,900               | 4,900                
|2009                                  | 600                 | 600                 | 800                  
|Total for all years undiscounted      | 39,400              | 40,800              | 63,800               
|Total for all years discounted at 10% | 34,900              | 35,900              | 55,700               

UNITED STATES

|                                      | Total Proved        | Total Proved        | Total Proved Plus    
|------------------------------------- | ------------------- | ------------------- | ---------------------
|                                      | Estimated Using     | Estimated Using     | Probable Estimated   
|                                      | Constant Prices and | Forecast Prices and | Using Forecast Prices
|                                      | Costs               | Costs               | and Costs            
|                                      | (M$)                | (M$)                | (M$)                 
|2005                                  | 29,075              | 29,374              | 29,771               
|2006                                  | 22,067              | 22,552              | 29,609               
|2007                                  | 7,468               | 7,723               | 10,091               
|2008                                  | 5,045               | 5,295               | 9,292                
|2009                                  | 5,029               | 5,353               | 10,472               
|Total for all years undiscounted      | 176,186             | 191,939             | 227,006              
|Total for all years discounted at 10% | 85,193              | 89,749              | 106,797              

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.

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Abandonment and Reclamation Costs
McDaniel estimated well abandonment costs for Provident's
Canadian properties based on average costs experienced in Provident's operating
areas. Well abandonments for the Canadian properties are scheduled at the end of
the economic life of each well. Abandonment of wells that are currently
suspended is scheduled over the economic life of each field, commencing in 2005.
Well and facility abandonment costs for the U.S. properties were estimated for
each field by Provident based upon operating practices and experience.
Abandonment of U.S. wells and facilities is scheduled at the end of the economic
life of each field.
Provident expects to abandon 3,187 net oil and gas wells in
total over the life of the reserves. The future net present values disclosed
herein are after abandonment costs. 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           | Canada | U.S.   | CONSOLIDATED
|--------------------------- | ------ | ------ | ------------
|(Constant Prices and Costs) | (M$)   | (M$)   | (M$)        
|                            |        |        |             
|2005                        | 6,800  | 0      | 6,800       
|2006                        | 6,200  | 0      | 6,200       
|2007                        | 5,100  | 0      | 5,100       
|3 year Subtotal             | 18,100 | 0      | 18,100      
|Total Undiscounted          | 77,900 | 16,404 | 94,304      
|Total Discounted @ 10%      | 43,190 | 372    | 43,562      

Forward Contracts

The effects of physical hedges have been included in the
future net revenues presented herein. Physical hedges are in place for Canadian
properties from the effective date to October 31, 2005. These hedges reduce
Canadian revenue by $166,594 based on forecast prices. No physical hedges are in
place for the U.S. properties.

Significant Factors or Uncertainties

There are no significant factors or uncertainties that may
impact the reserves and values other than those factors relating to the oil and
gas business in general as discussed in this Annual Information Form and in the
management's discussion and analysis for the year ended December 31, 2004.

Oil and Gas Properties and Wells

The following table sets forth the number of oil and gas wells in which
Provident held a working interest as at December 31, 2004. Service wells are not
included in these totals.

|                       | Producing Wells | Non-Producing Wells
|---------------------- | --------------- | -------------------
|                       | Oil             | Natural Gas        
|                       | Gross           | Net                
|Alberta                |                 |                    
|Lloydminster           | 449             | 390.3              
|West Central Alberta   | 648             | 145.6              
|Southern Alberta       | 407             | 277.9              
|Alberta Subtotal       | 1,504           | 813.8              
|                       |                 |                    
|Saskatchewan           |                 |                    
|Lloydminster           | 185             | 168.8              
|Southeast Saskatchewan | 967             | 175.7              
|Southwest Saskatchewan | 153             | 93.5               
|Saskatchewan Subtotal  | 1,305           | 438.0              

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|                 | Producing Wells | Non-Producing Wells
|---------------- | --------------- | -------------------
|                 | Oil             | Natural Gas        
|                 | Gross           | Net                
|British Columbia | 194             | 5.8                
|Canada Total     | 3,003           | 1,257.6            
|                 |                 |                    
|U.S.             |                 |                    
|                 |                 |                    
|California       |                 |                    
|Beverly Hills    | 30              | 29.7               
|Orcutt           | 87              | 82.1               
|Santa Fe Springs | 94              | 93.3               
|Other California | 202             | 136.5              
|Total California | 413             | 341.7              
|                 |                 |                    
|Wyoming          |                 |                    
|Lost Dome        | 6               | 1.9                
|                 |                 |                    
|U.S. Total       | 419             | 343.6              
|                 |                 |                    
|PROVIDENT TOTAL  | 3,422           | 1,601.2            

Notes:

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 top five most significant properties based upon net
present value using forecast prices and costs are as follows: (i) Beverly Hills
East is an oil and gas property located in Los Angeles County, California; (ii)
Santa Fe Springs is an oil property located in Los Angeles County, California;
(iii) Orcutt Hill is an oil property located in Santa Barbara County, California
(iv) Wildcat Hills is a gas property located in Southwest Alberta; and (v)
Enchant is an oil and gas property located in Southern Alberta.

All of Provident's Canadian properties are located onshore in
Western Canada. The United States properties are located onshore in California
and Wyoming. The individual value of each of these properties, with the
exception of Beverly Hills East, do not exceed ten percent of the total value of
the company's reserves on a total proved basis.

Beverly Hills East (West Pico Unit) was discovered by
Occidental Petroleum in 1964. A drillsite was built and development commenced in
1966 with the drilling of West Pico Unit #1 well. Production peaked in 1969 at
12,800 bopd and 33,000 Mcfpd of gas. Cumulative production from the West Pico
Unit is over 51 million barrels of oil and 78 Bcf of gas. Provident holds a 99%
working interest through its subsidiary, Breitburn Energy LP which acquired the
West Pico Unit from Occidental in 1993. Current production from 26 producing
wells is approximately 1,000 boepd(1) of light to medium crude oil
(approximately 28o API) and associated gas. Remaining Provident
interest total proved and proved plus probable reserves are estimated by NSA to
be 14.5 and 20.4 million barrels of oil equivalent(1), respectively,
as of December 31, 2004 at forecast prices and costs. Development potential
includes expansion of the existing pressure maintenance scheme (waterflood) as
well as infill development wells.

1. BOEs may be misleading, particularly if used in isolation. A BOE
  conversion ratio of 6 Mcf: 1 bbl is based on an energy equivalency conversion
  method primarily applicable at the burner tip and does not represent a value
  equivalency at the wellhead.

Properties with No Attributed Reserves

The following table sets out Provident's total land holdings with no
attributed reserves.

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|              |            |            |                          |            
|------------- | ---------- | ---------- | ------------------------ | -----------
|              | Gross Area | Net Area   | Expiries within one year | Work       
|              |            |            | Net Area                 | Commitments
|              | 1000 acres | 1000 acres | 1000 acres               |            
|Canada        | 828        | 461        | 74                       | 0          
|United States | 1          | 1          | 0                        | 0          
|              |            |            |                          |            

Costs Incurred

The following table summarizes the capital expenditures made by Provident on
oil and natural gas properties for the year ended December 31, 2004.

|             |                                   |            | Exploration | Development
|------------ | --------------------------------- | ---------- | ----------- | -----------
|             | Property
    Acquisition Costs(1) | Costs(1)   | Costs(1)   
|             | (M$)                              | (M$)       | (M$)       
|             |                                   | Unproved   |             |            
|             | Proved Properties                 | Properties |             |            
|Canada       | 444,428                           | 7,323      | 402         | 52,599     
|U.S.         | 278,766                           | 0          | 0           | 12,410     
|Consolidated | 723,194                           | 7,323      | 402         | 65,009     

Note:

1. All costs in Canadian dollars

Exploration and Development Activities

The following table sets forth the number of exploratory and development
wells which Provident completed during its 2004 financial year.

|                      | Exploratory Wells | Development Wells
|--------------------- | ----------------- | -----------------
|                      | Gross(1)          | Net(2)           
|Canada                |                   |                  
|Oil Wells             | -                 | -                
|Gas Wells             | -                 | -                
|Service Wells         | -                 | -                
|Standing and RR(3)    | -                 | -                
|Dry Holes             | -                 | -                
|Total Canada          | -                 | -                
|U.S.                  |                   |                  
|Oil Wells             | -                 | -                
|Gas Wells             | -                 | -                
|Service Wells         | -                 | -                
|Standing & RR         | -                 | -                
|Dry Holes             | -                 | -                
|Total U.S.            | -                 | -                
|Total Canada and U.S. | -                 | -                

Notes:

1. "Gross" wells mean the number of wells in which Provident has an interest.

2. "Net" wells means the aggregate number of wells obtained by multiplying each
gross well by Provident's percentage interest therein. 
3. RR means Rig Released

Production Estimates

The following tables set forth the production estimated for
2005 for Provident (company interest including royalty volumes earned) for the
reserves categories noted using Constant prices and costs and Forecast prices
and costs.

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2005 PRODUCTION ESTIMATES 
AVERAGE DAILY RATES 
CONSTANT PRICES AND COSTS

|                 | Light and  |           |         | Total     |         |           
|---------------- | ---------- | --------- | ------- | --------- | ------- | ----------
|                 | Medium Oil | Heavy Oil | NGL     | Oil & NGL | Gas     | Total     
|PROVED PRODUCING | (bbl/d)    | (bbl/d)   | (bbl/d) | (bbl/d)   | (Mcf/d) | (boe/d)(1)
|Canada           | 7,873      | 5,330     | 1,638   | 14,841    | 72,055  | 26,850    
|                 | 4,785      | 37        | 23      | 4,844     | 1,766   | 5,139     
|U.S.             |            |           |         |           |         |           
|Consolidated     | 12,658     | 5,366     | 1,661   | 19,685    | 73,821  | 31,989    
|                 |            |           |         |           |         |           
|                 | Light and  |           |         | Total     |         |           
|                 | Medium Oil | Heavy Oil | NGL     | Oil & NGL | Gas     | Total     
|TOTAL PROVED     | (bbl/d)    | (bbl/d)   | (bbl/d) | (bbl/d)   | (Mcf/d) | (boe/d)(1)
|Canada           | 8,034      | 6,337     | 1,853   | 16,225    | 81,918  | 29,878    
|                 | 5,401      | 36        | 125     | 5,562     | 2,368   | 5,956     
|U.S.             |            |           |         |           |         |           
|Consolidated     | 13,435     | 6,373     | 1,978   | 21,786    | 84,286  | 35,834    

Note:

1. BOEs may be misleading, particularly if used in isolation. A BOE
  conversion ratio of 6 Mcf: 1 bbl is based on an energy equivalency conversion
  method primarily applicable at the burner tip and does not represent a value
  equivalency at the wellhead.

2005 PRODUCTION ESTIMATES 
AVERAGE DAILY RATES 
FORECAST PRICES AND COSTS

|                  | Light and  |           |         | Total     |         |           
|----------------- | ---------- | --------- | ------- | --------- | ------- | ----------
|                  | Medium Oil | Heavy Oil | NGL     | Oil & NGL | Gas     | Total     
|PROVED PRODUCING  | (bbl/d)    | (bbl/d)   | (bbl/d) | (bbl/d)   | (Mcf/d) | (boe/d)(1)
|Canada            | 7,952      | 5,652     | 1,638   | 15,243    | 72,055  | 27,252    
|                  | 4,783      | 37        | 23      | 4,843     | 1,766   | 5,137     
|U.S.              |            |           |         |           |         |           
|Consolidated      | 12,736     | 5,689     | 1,661   | 20,086    | 73,821  | 32,389    
|                  |            |           |         |           |         |           
|                  | Light and  |           |         | Total     |         |           
|                  | Medium Oil | Heavy Oil | NGL     | Oil & NGL | Gas     | Total     
|TOTAL PROVED      | (bbl/d)    | (bbl/d)   | (bbl/d) | (bbl/d)   | (Mcf/d) | (boe/d)(1)
|Canada            | 8,113      | 6,661     | 1,854   | 16,628    | 81,918  | 30,281    
|                  | 5,399      | 36        | 124     | 5,560     | 2,368   | 5,955     
|U.S.              |            |           |         |           |         |           
|Consolidated      | 13,513     | 6,697     | 1,978   | 22,188    | 84,286  | 36,236    
|                  |            |           |         |           |         |           
|                  | Light and  |           |         | Total     |         |           
|                  | Medium Oil | Heavy Oil | NGL     | Oil & NGL | Gas     | Total     
|PROVED + PROBABLE | (bbl/d)    | (bbl/d)   | (bbl/d) | (bbl/d)   | (Mcf/d) | (boe/d)(1)
|Canada            | 8,404      | 7,596     | 1,927   | 17,927    | 86,575  | 32,356    
|                  | 5,733      | 36        | 130     | 5,900     | 2,737   | 6,356     
|U.S.              |            |           |         |           |         |           
|Consolidated      | 14,137     | 7,632     | 2,058   | 23,827    | 89,312  | 38,712    

Note:

1. BOEs may be misleading, particularly if used in isolation. A BOE
  conversion ratio of 6 Mcf: 1 bbl is based on an energy equivalency conversion
  method primarily applicable at the burner tip and does not represent a value
  equivalency at the wellhead.

Production History

The following tables set forth certain information in respect
of production, product prices received, royalties, production costs and netbacks
received by Provident for each quarter of its most recently completed financial
year.

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CANADA

|                             | Three Months Ended | Three Months Ended | Three Months Ended | Three Months Ended
|---------------------------- | ------------------ | ------------------ | ------------------ | ------------------
|                             | March 31, 2004     | June 30, 2004      | September 30, 2004 | December 31, 2004 
|Average Daily Production     |                    |                    |                    |                   
|Light and Medium Oil (bbl/d) | 5,965              | 7,319              | 9,387              | 9,281             
|Heavy Oil (bbl/d)            | 6,588              | 6,537              | 6,770              | 6,536             
|Natural Gas (Mcf/d)          | 63,858             | 67,732             | 87,078             | 85,803            
|Natural Gas Liquids (bbl/d)  | 1,130              | 1,263              | 1,782              | 1,746             
|Average Net Prices Received  |                    |                    |                    |                   
|Light and Medium Oil ($/bbl) | 39.00              | 41.85              | 46.68              | 42.00             
|Heavy Oil ($/bbl)            | 26.84              | 28.26              | 34.23              | 25.33             
|Natural Gas ($/Mcf)          | 6.40               | 6.99               | 6.47               | 6.53              
|Natural Gas Liquids ($/bbl)  | 37.03              | 40.57              | 40.88              | 42.66             
|Royalties                    |                    |                    |                    |                   
|Light and Medium Oil ($/bbl) | 7.55               | 8.96               | 9.22               | 8.40              
|Heavy Oil ($/bbl)            | 5.29               | 5.46               | 6.75               | 5.08              
|Natural Gas ($/Mcf)          | 1.20               | 1.51               | 1.67               | 1.41              
|Natural Gas Liquids ($/bbl)  | 9.74               | 11.83              | 10.16              | 9.12              
|Production Costs             |                    |                    |                    |                   
|Light and Medium Oil ($/bbl) | 10.69              | 9.27               | 12.58              | 13.61             
|Heavy Oil ($/bbl)            | 8.29               | 8.81               | 9.15               | 11.85             
|Natural Gas ($/Mcf)          | 1.20               | 1.05               | 1.13               | 0.87              
|Natural Gas Liquids ($/bbl)  | 7.21               | 6.34               | 6.80               | 5.27              
|Netback Received             |                    |                    |                    |                   
|Light and Medium Oil ($/bbl) | 20.76              | 23.62              | 24.88              | 19.99             
|Heavy Oil ($/bbl)            | 13.26              | 13.99              | 18.33              | 8.40              
|Natural Gas ($/Mcf)          | 4.00               | 4.43               | 3.67               | 4.25              
|Natural Gas Liquids ($/bbl)  | 20.08              | 22.40              | 23.92              | 28.27             

Note:

1. All Pricing and Netbacks exclude Provident's hedging program

UNITED STATES

|                                 | Three Months Ended | Three Months Ended | Three Months Ended | Three Months Ended
|-------------------------------- | ------------------ | ------------------ | ------------------ | ------------------
|                                 | March 31, 2004(1)  | June 30, 2004(1)   | September 30, 2004 | December 31, 2004 
|Average Daily Production         |                    |                    |                    |                   
|Light and Medium Oil
    (bbl/d) | N/A                | N/A                | 3,216              | 4,676             
|Heavy Oil (bbl/d)                | N/A                | N/A                | 29                 | 28                
|Natural Gas (Mcf/d)              | N/A                | N/A                | 1,563              | 1,536             
|Natural Gas Liquids
    (bbl/d)  | N/A                | N/A                | -                  | -                 
|Average Net Prices Received      |                    |                    |                    |                   
|Light and Medium Oil
    ($/bbl) | N/A                | N/A                | 53.18              | 52.68             
|Heavy Oil ($/bbl)                | N/A                | N/A                | 51.30              | 53.32             
|Natural Gas ($/Mcf)              | N/A                | N/A                | 7.40               | 7.75              
|Natural Gas Liquids
    ($/bbl)  | N/A                | N/A                | -                  | -                 
|Royalties                        |                    |                    |                    |                   
|Light and Medium Oil
    ($/bbl) | N/A                | N/A                | 5.12               | 4.35              
|Heavy Oil ($/bbl)                | N/A                | N/A                | 3.08               | 3.20              
|Natural Gas ($/Mcf)              | N/A                | N/A                | 0.97               | 1.04              
|Natural Gas Liquids
    ($/bbl)  | N/A                | N/A                | -                  | -                 
|Production Costs                 |                    |                    |                    |                   
|Oil ($/bbl)                      | N/A                | N/A                | 15.82              | 15.16             
|Natural Gas ($/Mcf)              | N/A                | N/A                | incl.              | incl.             
|Natural Gas Liquids
    ($/bbl)  | N/A                | N/A                | incl.              | incl.             
|Netback Received                 |                    |                    |                    |                   
|Oil ($/bbl)                      | N/A                | N/A                | 31.81              | 32.95             
|Natural Gas ($/Mcf)              | N/A                | N/A                | incl.              | incl.             
|Natural Gas Liquids
    ($/bbl)  | N/A                | N/A                | incl.              | incl.             

Notes:

1. United States properties were acquired June 2004 
2. All Pricing and Netbacks exclude Provident's hedging program

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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.



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.

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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.

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.

- 57 -

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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

> Extraction

An extraction facility's fees may be based either on a
cost-of-service arrangement (reimbursement for operating expenses plus a deemed
return on capital employed) or tied to production. In order to produce NGLs, the
owner of the facility must purchase natural gas (referred to as shrinkage gas)
to replace the energy removed from the natural gas stream in the form of NGLs as
part of the extraction process. The cost of the shrinkage make-up gas, which is
typically tied to a benchmark natural gas price, accounts for approximately 80%
of a facility's total costs. For the right to extract NGLs from the gas stream,
extraction facility owners generally pay shippers a premium to the shrinkage gas
price, which effectively amounts to sharing with shippers a portion of the value
that is added through the recovery and sale of NGLs. Other expenses include
electrical power, labour, maintenance, property taxes, insurance and other
overhead.

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

- 58 -

---



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).

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, 8.75% Debentures, 8% Debentures and 6.5%
Debenture of the Trust are listed and posted for trading on the TSX under the
symbol PVE.DB, PVE.DB.A, PVE.DB.B and PVE.DB.C, respectively.

The following table summarizes the Trust Unit and debenture trading activity
for the periods indicated on both the Toronto Stock Exchange and the American
Stock Exchange, as applicable.

Toronto Stock Exchange

> Trust Units

|Period           |     | High    | Low     | Volume (000's)
|---------------- | --- | ------- | ------- | --------------
|2004             |     |         |         |               
|January          |     | $11.53  | $10.98  | 4,008         
|February         |     | $10.99  | $10.14  | 4,625         
|March            |     | $10.90  | $10.30  | 4,523         
|April            |     | $11.77  | $10.65  | 8,581         
|May              |     | $11.75  | $10.98  | 3,775         
|June             |     | $11.12  | $10.29  | 12,918        
|July             |     | $10.50  | $10.20  | 6,219         
|August           |     | $10.84  | $10.31  | 7,656         
|September        |     | $11.39  | $10.82  | 12,986        
|October          |     | $11.71  | $10.78  | 9,164         
|November         |     | $11.20  | $10.70  | 6,327         
|December         |     | $11.78  | $10.71  | 6,360         
|                 |     |         |         |               
|10.5% Debentures |     |         |         |               
|Period           |     | High    | Low     | Volume        
|2004             |     |         |         |               
|January          |     | $113.99 | $107.01 | 14,930        
|February         |     | $108.50 | $105.50 | 20,340        
|March            |     | $112.00 | $108.75 | 6,090         
|April            |     | $112.00 | $105.00 | 9,425         
|May              |     | $110.00 | $106.50 | 3,670         
|June             |     | $108.50 | $106.50 | 5,640         
|July             |     | $109.49 | $106.15 | 10,245        
|August           |     | $109.98 | $105.50 | 24,130        
|September        |     | $110.49 | $107.54 | 4,990         
|October          |     | $111.00 | $107.50 | 10,590        
|November         |     | $108.74 | $107.03 | 9,270         
|December         |     | $114.85 | $108.00 | 56,910        
|                 |     |         |         |               
|8.75% Debentures |     |         |         |               
|Period           |     | High    | Low     | Volume        
|2004             |     |         |         |               
|January          |     | $108.00 | $105.00 | 18,140        
|February         |     | $108.00 | $103.50 | 9,030         
|March            |     | $113.00 | $105.00 | 7,760         
|April            |     | $108.98 | $104.00 | 11,130        
|May              |     | $107.00 | $103.50 | 60,960        
|June             | ... | $105.50 | $103.50 | 15,120        
|July             |     | $107.00 | $98.60  | 6,320         
|August           |     | $105.50 | $102.12 | 5,970         
|September        |     | $107.00 | $104.00 | 8,200         

- 59 -

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|              |         |         |        
|------------- | ------- | ------- | -------
|Period        | High    | Low     | Volume 
|2004          |         |         |        
|October       | $109.00 | $105.50 | 4,430  
|November      | $106.75 | $104.75 | 2,640  
|December      | $113.99 | $106.00 | 4,310  
|              |         |         |        
|8% Debentures |         |         |        
|Period        | High    | Low     | Volume 
|2004          |         |         |        
|July(1)       | $103.00 | $99.25  | 148,095
|August        | $103.75 | $101.30 | 18,345 
|September     | $104.64 | $102.01 | 10,650 
|October       | $107.00 | $104.00 | 5,710  
|November      | $106.00 | $103.50 | 9,350  
|December      | $110.95 | $104.00 | 142,060

Note:

(1) The 8% Debentures were listed on the TSX on July 6, 2004.

American Stock Exchange

> Trust Units

|Period    | High  | Low   | Volume (000's)
|--------- | ----- | ----- | --------------
|2004      |       |       |               
|January   | $9.06 | $8.20 | 12,348        
|February  | $8.22 | $7.59 | 13,130        
|March     | $8.24 | $7.79 | 10,694        
|April     | $8.74 | $8.22 | 22,526        
|May       | $8.56 | $8.03 | 8,979         
|June      | $8.14 | $7.63 | 17,216        
|July      | $7.93 | $7.74 | 11,933        
|August    | $8.24 | $7.86 | 16,948        
|September | $8.94 | $8.31 | 21,186        
|October   | $9.54 | $8.82 | 25,038        
|November  | $9.50 | $8.75 | 15,867        
|December  | $9.57 | $9.00 | 21,306        

RECORD OF CASH DISTRIBUTIONS

The following table sets forth the per Trust Unit amount of monthly cash
distributions paid by the Trust since its inception.

|                   |                         | Distribution
|------------------ | ----------------------- | ------------
|                   | Distribution
    Amount | Amount      
|                   | (Cdn$)                  | (US$)(1)    
|2001               |                         |             
|March - December   | $2.54                   | $1.64       
|                   |                         |             
|2002               |                         |             
|January - December | $2.03                   | $1.29       
|                   |                         |             
|2003               |                         |             
|January - December | $2.06                   | $1.47       
|                   |                         |             
|2004               |                         |             
|January            | 0.12                    | 0.09        
|February           | 0.12                    | 0.09        
|March              | 0.12                    | 0.09        

- 60 -

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|                       |                         | Distribution
|---------------------- | ----------------------- | ------------
|                       | Distribution
    Amount | Amount      
|                       | (Cdn$)                  | (US$)(1)    
|April                  | 0.12                    | 0.09        
|May                    | 0.12                    | 0.09        
|June                   | 0.12                    | 0.09        
|July                   | 0.12                    | 0.09        
|August                 | 0.12                    | 0.09        
|September              | 0.12                    | 0.09        
|October                | 0.12                    | 0.09        
|November               | 0.12                    | 0.09        
|December               | 0.12                    | 0.10        
|Total for 2004         | $1.44                   | $1.09       
|                       |                         |             
|2005                   |                         |             
|January                | 0.12                    | 0.10        
|February               | 0.12                    | 0.10        
|March                  | 0.12                    | 0.10        
|Total to date for 2005 | $0.36                   | $0.30       

Since its inception, the Trust has paid an aggregate of $8.43 (US$5.80) in
cash distributions to Unitholders.

Note:

(1) The exchange rate is based on the Bank of Canada noon rate on the payment
date.

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:

|                         |                                                    |                           | 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                      | 40,000                   
|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                      | 1,030,540 (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.                                              |                           |                          

- 61 -

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|                            |                                               |                       |                      
|--------------------------- | --------------------------------------------- | --------------------- | ---------------------
|                            |                                               |                       | Number of Trust Units
|Name and Municipality of    |                                               | Director of Provident | Beneficially Owned or
|Residence                   | Principal Occupation                          | Since                 | Controlled           
|Randall J. Findlay          | President of Provident since March 2001.      | 2001                  | 982,645 (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                  | 48,495               
|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                  | 56,974               
|Calgary, Alberta            | Corporation (Chartered Accountants).          |                       |                      
|                            |                                               |                       |                      
|Byron J. Seaman (3)         | Independent businessman and private investor. | 2001                  | 88,735               
|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                  | 20,003               
|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 (2), (5)     | President, Gish Consulting Inc., energy       | 2003                  | 5,000                
|                            | 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.                                 |                       |                      
|                            |                                               |                       |                      
|Dr. Robert Mitchell (3)     | Independent businessman since September       | 2004                  | 3,000                
|                            | 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.         |                       |                      
|                            |                                               |                       |                      
|Hugh A. Fergusson(1)(3)     | Former Vice President and Director with Dow   | 2005                  | Nil                  
|                            | Chemical Canada Inc., Director and advisor to |                       |                      
|                            | a number of public and private corporations   |                       |                      
|                            | including the Canadian Energy Research        |                       |                      
|                            | Institute and Taylor NGL Limited Partnership. |                       |                      

|      
|------
|Notes:
|(1)   
|(2)   
|(3)   
|(4)   
|(5)   

- 62 -

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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 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.

- 63 -

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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.
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 Governance, Human Resources and Compensation
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.- 64 -

> 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.

> Hugh A. Fergusson

Director

Mr. Fergusson has been a member of Provident's Board of
Directors since March 1, 2005 and serves on the Audit Committee and the
Reserves, Operations, Environmental, Health and Safety Committee. Mr. Fergusson
is the former Vice President and Director of Dow Chemical Canada Inc. He is also
a director and advisor to a number of public and private corporations including
the Canadian Energy Research Institute and Taylor NGL Limited Partnership.

> 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 leader of
financial reporting for Sceptre Resources, first joining that 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.

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.

- 65 -

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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 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. Hugh Fergusson. 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

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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.
See "Audit Committee Information" and Schedule C of this Annual Information Form
for additional information relating to the Audit Committee.

> Governance, Human Resources and Compensation Committee

The Governance, Human Resources and Compensation Committee
consists of Mr. John B. Zaozirny (Chairman), Mr. Grant D. Billing, Mr. Jeffrey
T. Smith and Mr. Norman Gish. 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.

> Reserves, Operations, Environment, Health and Safety Committee

The Reserves, Operations and Environmental, Health and Safety
Committee consists of Mr. Jeffrey T. Smith (Chairman), Dr. Robert Mitchell, Mr.
Bruce R. Libin, Mr. Byron J. Seaman and Mr. Hugh Fergusson. 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.

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> 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.

AUDIT COMMITTEE INFORMATION

Composition of the Audit Committee

The Audit Committee consists of three members, all of whom are independent
and financially literate, as defined by Multilateral Instrument 52-110 Audit
Committees.

Audit Committee Charter

The full text of the Trust's Audit Committee Charter is set forth in Schedule
C of this Annual Information Form.

Relevant Education and Experience of Each Audit Committee Member

The following table sets out the relevant education and experience of each of
the members of the Audit Committee:

|                     |             | Financially |                                                              
|-------------------- | ----------- | ----------- | -------------------------------------------------------------
|Name                 | Independent | Literate    | Relevant Education and Experience                            
|                     |             |             |                                                              
|M.H. (Mike) Shaikh   | Yes         | Yes         | Mr. Shaikh holds the degree of Bachelor of Commerce          
|                     |             |             | and is a Chartered Accountant. As a Chartered                
|                     |             |             | Accountant, Mr. Shaikh attained experience in                
|                     |             |             | preparing, auditing, analyzing and evaluating
    financial  
|                     |             |             | statements. Mr. Shaikh has an understanding
    of the       
|                     |             |             | accounting principles used by Provident as
    well as the   
|                     |             |             | implications of those accounting principles
    on           
|                     |             |             | Provident's financial results. Mr. Shaikh has
    also       
|                     |             |             | obtained significant financial experience and
    exposure   
|                     |             |             | to accounting and financial issues as the
    President of   
|                     |             |             | M.H. Shaikh Professional Corporation and in
    his role     
|                     |             |             | as a director and audit committee member of
    various      
|                     |             |             | public companies.                                            
|                     |             |             |                                                              
|Bruce R. Libin, Q.C. | Yes         | Yes         | Mr. Libin holds the degree of Bachelor of
    Commerce       
|                     |             |             | (Honours), Master of Business Administration
    and         
|                     |             |             | Juris Doctoris. Mr. Libin has obtained
    significant       
|                     |             |             | financial experience and exposure to
    accounting,         
|                     |             |             | disclosure, internal controls and financial
    issues during
|                     |             |             | his legal practice, his business experience
    (including as
|                     |             |             | Chief Executive Officer of Beau Canada
    Exploration       
|                     |             |             | Ltd. and as Executive Chairman and Chief
    Executive       
|                     |             |             | Officer of Destiny Resource Services Corp.)
    and his      

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|                  |             |             |                                                            
|----------------- | ----------- | ----------- | -----------------------------------------------------------
|                  |             | Financially |                                                            
|Name              | Independent | Literate    | Relevant Education and Experience                          
|                  |             |             |                                                            
|                  |             |             | service on the audit committee of several boards
    of    
|                  |             |             | directors, including Amoco
    Canada Petroleum            
|                  |             |             | Company Limited, Maxx Petroleum
    Ltd., Mark's Work      
|                  |             |             | Warehouse Ltd., Calgary Health
    Region, Southern        
|                  |             |             | Alberta Institute to Technology,
    NQL Drilling Tools    
|                  |             |             | Ltd., and Winstar Resources Ltd.                           
|                  |             |             |                                                            
|Hugh A. Fergusson | Yes         | Yes         | Mr. Fergusson holds the degrees
    of Bachelor of Arts    
|                  |             |             | and Bachelor of Laws. He has
    also completed            
|                  |             |             | Advanced Management Programs at
    the University of      
|                  |             |             | Western Ontario and Northwestern
    University. He is     
|                  |             |             | an independent businessman and
    Corporate Director.     
|                  |             |             | Mr. Fergusson practiced law for
    five years following   
|                  |             |             | which he was employed by the Dow
    Chemical              
|                  |             |             | Company (and related companies)
    for 27 years until he  
|                  |             |             | retired in 2004. During his
    career with Dow, Mr.       
|                  |             |             | Fergusson obtained significant
    financial experience and
|                  |             |             | exposure to accounting and
    financial issues through a  
|                  |             |             | series of roles including
    commercial and business      
|                  |             |             | leadership largely related to
    hydrocarbons and energy. 
|                  |             |             | In addition to being a director
    of a number of Dow     
|                  |             |             | subsidiaries, Mr. Fergusson was
    Chairman of            
|                  |             |             | Petromont Inc. from 2002 until
    2004 and a member of    
|                  |             |             | its Audit Committee from 2002
    until 2004.              

External Auditor Service Fees

The following table sets forth information about the fees billed to the Trust
for professional services provided by PricewaterhouseCoopers LLP during fiscal
2004 and 2003:

|(CDN$)             | 2004       | 2003    
|------------------ | ---------- | --------
|Audit Fees         | $868,000   | $362,100
|Audit-Related Fees | 90,750     | 140,000 
|Tax Fees           | 375,000    | 214,700 
|All Other Fees     | -          | -       
|Total              | $1,333,750 | $716,800

INFORMATION CONCERNING THE OIL AND GAS INDUSTRY

Canadian Government Regulation

The oil and natural gas industry is subject to extensive
controls and regulations, imposed by various levels of government. Outlined
below are some of the more significant aspects of the relevant legislation and
regulations. It is not expected that any of such controls and regulations will
affect the operations of Provident in a manner materially different than they
will affect other oil and gas companies of similar size.

Pricing and Marketing - Oil

Producers of oil negotiate sales contracts directly with oil
purchasers, with the result that the market determines the price of oil. Such
price depends in part on oil quality, price of competing oils, distance to
market and the value of refined products. Oil exporters are also entitled to
enter into export contracts and export oil provided that, for contracts, which
do not exceed one year in the case of light crude oil and two

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years in the case of heavy crude oil, an export order must be
obtained from the National Energy Board prior to the export. Any export pursuant
to a contract of longer duration must be made pursuant to a National Energy
Board export licence and Governor in Council approval.

Pricing and Marketing - Natural Gas

The price of natural gas sold in intra-provincial and
inter-provincial trade is determined by negotiation between buyers and sellers.
Natural gas exported from Canada is subject to regulation by the National Energy
Board and the government of Canada. The price received by Provident depends, in
part, on the prices of competing natural gas and other substitute fuels, access
to downstream transportation, distance to markets, length of the contract term,
weather conditions, the supply and demand balance and other contractual terms.
Exporters are free to negotiate prices with purchasers, provided that the export
contracts must continue to meet certain criteria prescribed by the National
Energy Board and the government of Canada. As in the case with oil, natural gas
exports for a term of less than two years must be made pursuant to a National
Energy Board order and in the case of exports for a longer duration, pursuant to
a National Energy Board licence and Governor in Council approval.

The government of Alberta also regulates the volume of natural gas which may
be removed from the Province for consumption elsewhere.

The North American Free Trade Agreement

On January 1, 1994 the North American Free Trade Agreement
("NAFTA") among the governments of Canada, the United States and Mexico became
effective. NAFTA carries forward most of the material energy terms contained in
the Canada-U.S. Free Trade Agreement. In the context of energy resources, Canada
continues to remain free to determine whether exports to the U.S. or Mexico will
be allowed provided that the restrictions are otherwise justified under certain
provisions of the General Agreement on Tariffs and Trade and then only if any
export restrictions do not: (i) reduce the proportion of the energy resource
exported relative to the total supply of energy resource (based upon the
proportions prevailing in the most recent 36 months); (ii) impose an export
price higher than the domestic price; or (iii) disrupt normal channels of
supply. All three countries are prohibited from imposing minimum export or
import price requirements.

NAFTA contemplates the reduction of Mexican restrictive trade
practices in the energy sector and prohibits discriminatory border restrictions
and export taxes. The agreement also contemplates clearer disciplines on
regulators to avoid discriminatory actions and to minimize disruption of
contractual arrangements.

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 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

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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 Development

Exploitation and development risks are due to the uncertain
results of searching for and producing oil and natural gas using imperfect
scientific methods. These risks are mitigated by using experienced staff,
focusing exploitation efforts in areas in which Provident has existing knowledge
and expertise or access to such expertise, using up-to-date technology to
enhance methods and controlling costs to maximize returns. Advanced oil and
natural gas related technologies such as three dimensional seismography,
reservoir simulation studies and horizontal drilling have been used by Provident
and will be used by Provident to improve its ability to find, develop and
produce oil and natural gas.

> Operations

Provident's operations will be subject to all of the risks
normally incident to the operation and development of oil and natural gas
properties and the drilling of oil and natural gas wells, including encountering
unexpected formations or pressures, blowouts, craterings and fires, all of which
could result in personal injuries, loss of life and damage to property of
Provident and others. Provident will have both safety and environmental policies
in place to protect its operators and employees, as well as to meet the
regulatory requirements in those areas where it operates. In addition, Provident
will have liability insurance policies in place, in such amounts as it considers
adequate, however, it will not be fully insured against all of these risks, nor
are all such risks insurable.

Continuing production from a property, and to some extent the
marketing of production therefrom, are largely dependent upon the ability of the
operator of the property. To the extent the operator fails to perform these
functions properly, revenue may be reduced. Payments from production generally
flow through the operator and there is a risk of delay and additional expense in
receiving such revenues if the operator becomes insolvent. Although satisfactory
title reviews are generally conducted in accordance with industry standards,
such reviews do not guarantee or certify that a defect in the chain of title may
not arise to defeat the claim of Provident to certain of its oil and gas
properties. A reduction of the income from the Provident Royalties could result
in such circumstances.

> Oil and Natural Gas Prices

The price of oil and natural gas will fluctuate throughout
the life of Provident and price and demand are factors largely beyond its
control. Such fluctuations will have a positive or negative effect on the
revenue to be received by it. Such fluctuations will also have an effect on the
acquisition costs of any future oil and natural gas properties that Provident
may acquire. As well, cash distributions from the Trust will be highly sensitive
to the prevailing price of crude oil and natural gas.

> Marketing

The marketability and price of oil and natural gas, which may
be acquired or discovered by Provident, will be affected by numerous factors
beyond its control. These factors include demand for oil and natural gas, market
fluctuations, the proximity and capacity of oil and natural gas pipelines and
processing equipment and government regulations, including regulations relating
to environmental protection, royalties, allowable production, pricing, importing
and exporting of oil and natural gas.

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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 $410
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, NSA, CGA 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.

> 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

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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 Throughput

The 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 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.

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Bank Financing

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.

> 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.

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> 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 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 Ownership

Generally, a trust cannot qualify as a "mutual fund trust"
for the purposes of the Tax Act if it is established or is being maintained
primarily for the benefit of non-residents. Although not without uncertainty,
this is generally accepted to exist in most situations where Non-Resident
holders own significantly in excess of 50% 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". The Budget
proposed to remove this exception. However, the proposal to remove this
exception was subsequently withdrawn in a subsequent announcement by the
Department of Finance. There can be no assurance that the treatment of mutual
fund trusts will not be changed in a manner which adversely affects Trust
Unitholders.

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;
|--- | ---------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------

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|    |                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                     
|--- | ------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
|(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. The February 23, 2005 Federal
    Budget proposed that the limit in respect of foreign property that may be
    held by pension funds and other deferred plans be eliminated for months that
    end in the 2005 and subsequent calendar year;                                                                                                                                                                                                                                                       
|    |                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                     
|(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 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.                                                                                                                                                                                                                                                                                                                                                                                                                                                                                           

For the purpose of maintaining the Trust's status 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;

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|(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, areappropriate in the circumstances that will reduce or limit the number of
    Trust Units held by non-resident Unitholders to ensure that the Trust is not
    maintained primarily for the benefit of non-residents.

> 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, registered education savings plans
and registered retirement income funds.

> 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.

- 78 -

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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.

On July 1, 2004 the Income Trusts Liability Act
(Alberta) came into force. This Act creates a statutory limitation on the
liability of unitholders of Alberta income trusts such as the Trust. The
legislation provides that a unitholder will not be, as a beneficiary, liable for
any act, default, obligation or liability of the trustee that arises after the
legislation come into effect.

> Regulatory Matters

Provident's operations are subject to a variety of federal, provincial laws
and regulations, including laws and regulations relating to the protection of
the environment.

> Conflicts of Interest

The directors and officers of Provident are engaged in and
will continue to engage in other activities in the oil and natural gas industry
and, as a result of these and other activities, the directors and officers of
Provident may become subject to conflicts of interest. The ABCA provides that in
the event that a director has an interest in a contract or proposed contract or
agreement, the director shall disclose his interest in such contract or
agreement and shall refrain from voting on any matter in respect of such
contract or agreement unless otherwise provided under the ABCA. To the extent
that conflicts of interest arise, such conflicts will be resolved in accordance
with the provisions of the ABCA. The business of Provident is subject to other
risks and matters, which are outside of their control.

> Competition

The industry is highly competitive in the acquisition of exploration
prospects and the development of new sources of production and the sale of oil
and natural gas.

> Dependence on Key Personnel

The success of the operations of Provident will be largely
dependent on the skills and expertise of key personnel to manage the overall
business and, in the NGL marketing business, to achieve positive margins. The
continued success of Provident will be dependent on its ability to retain or
recruit such personnel.

> Variations in Interest Rates and Foreign Exchange Rates

Variations in interest rates could result in a significant change in the
amount Provident pays to service debt, potentially impacting distributions to
Unitholders.

In addition, the exchange rate for the Canadian dollar versus
the U.S. dollar has increased significantly over the last 12 months, resulting
in the receipt by the Trust of fewer Canadian dollars for its production which
may affect future distributions. Provident has initiated certain hedges to
mitigate these risks. The increase in the exchange rate for the Canadian dollar
and future Canadian/United States exchange rates may impact future distributions
and the future value of the Trust's reserves as determined by independent
evaluators.

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Statutory Remedies

The Trust is not a legally recognized entity within the relevant definitions
of the Bankruptcy and Insolvency Act (Canada), the Companies'
Creditors Arrangement Act (Canada) and in some cases, the
Winding Up and Restructuring Act (Canada). As a result,
in the event a restructuring of the Trust were necessary, the Trust would not be
able to access the remedies available thereunder. In the event of a
restructuring, a holder of Debentures may be in a different position than a
holder of unsecured indebtedness of a corporation.

Availability of Credit

As of March 21, 2005, the Trust had drawn $177.0 million
against the credit facility and had $48.7 million of the credit facility drawn
on letters of credit. Variations in interest rates and scheduled principal
repayments or the need to refinance the credit facility upon expiration could
result in significant changes in the amount required to be applied to debt
service before payment of any amounts to the Trust. Although it is believed that
the credit facility is sufficient, there can be no assurance that the amount
will be adequate for the financial obligations of the Trust, that additional
funds can be obtained or that, upon expiration, the credit facility can be
refinanced on terms acceptable to the Trust or the lenders. In such
circumstances, cash distributions may be reduced.

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 and the debentures is
Computershare Trust Company of Canada at its principal offices in Toronto,
Ontario and Calgary, Alberta.

INTERESTS OF EXPERTS

As of the date hereof, the principals of McDaniel,
independent oil and gas reservoir engineers, as a group, beneficially own,
directly or indirectly, less than 1 percent of the Trust Units. As of the date
hereof, the principals of NSA, independent oil and gas reservoir engineers, as a
group, beneficially own, directly or indirectly, less than 1 percent of the
Trust Units. As of the date hereof, the principals of CGA, independent oil and
gas reservoir engineers, as a group, beneficially own, directly or indirectly,
less than 1 percent of the Trust Units. As of the date hereof, the principals of
GLJ, independent oil and gas reservoir engineers, as a group, beneficially own,
directly or indirectly, less than 1 percent of the Trust Units.

MATERIAL CONTRACTS

Other than the Trust Indenture, there are no material
contracts entered into by the Trust or its subsidiaries during the most recently
completed financial year or since January 1, 2002 and which are still in effect,
other than contracts entered into in the ordinary course of business.

- 80 -

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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.

PRINCIPAL HOLDERS OF TRUST UNITS

As at the date hereof, to the knowledge of Provident, no
person or company owned of record or beneficially, directly or indirectly, more
than 10% of the issued and outstanding Trust Units. As at March 24, 2005, the
directors and senior officers of Provident, as a group, beneficially owned,
directly or indirectly, 1,436,000 Trust Units or approximately 1.0% of the
issued and outstanding Trust Units and 638,474 Series A exchangeable shares of
Provident representing 100% of the issued and outstanding Series A exchangeable
shares of Provident. As of March 24, 2005, each such Series A exchangeable share
of Provident held by such director or senior officer is exchangeable into Trust
Units at an exchange ratio of 1.39162. The directors and senior officers of
Provident do not beneficially own, directly or indirectly, or exercise control
or direction over any of the Series B exchangeable shares of Provident.

ADDITIONAL INFORMATION

Additional information related to the remuneration of the
directors and officers of Provident for the year ended December 31, 2004, the
indebtedness of the directors and officers of Provident, the principal holders
of Trust Units and securities authorized for issuance under equity compensation
plans, where applicable, is contained in the Management Proxy Statement and
Information Circular of the Trust dated March 31, 2005, which relates to the
Annual Meeting of the Unitholders to be held on May 5, 2005. 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, 2004.

Additional copies of this Annual Information Form are available on SEDAR at
www.sedar.com or may be obtained from Provident. Please contact:

- 81 -

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Jennifer Pierce 
Investor Relations 
Provident Energy Ltd. 
700, 112 - 4th Street S.W. 
Calgary, Alberta T2P 0H3

Telephone: (403) 296-2233 
Fax:             
(403) 261-6696

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



- 82 -

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SCHEDULE A

REPORTS ON RESERVES DATA BY INDEPENDENT QUALIFIED RESERVES
EVALUATOR OR AUDITOR



February 25, 2005

Provident 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, 2004. The reserves data consists of the following:

> (a) proved and proved plus probable oil and
>     gas reserves estimated as at December 31, 2004 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, 2004 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).
2. 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.

Suite 2200, Bow Valley Square 3, 255-5th Avenue
S.W., Calgary, Alberta T2P 3G6 
Tel: (403) 262-5506 Fax: (403) 233-2744 Email: mcdaniel@mcdan.com Website:
www.mcdan.com

A-1

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|Provident Energy Ltd.     | Page 2           
|------------------------- | -----------------
|Forecast Prices and Costs | February 25, 2005

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, 2004, 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, 2004   | 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 P. A. Welch" 
_________________________ 
P. A. Welch, P. Eng. 
Executive Vice President

Calgary, Alberta

McDANIEL & ASSOCIATES Consultants Ltd.

A-2

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The Board of Directors 
BreitBurn Energy Company LP 
Suite 4800 
515 South Flower Street 
Los Angeles, California 90071

RE: Form 51-101F2 
       Report on Reserves Data by an Independent
Qualified Reserves Evaluator of BreitBurn Energy Company LP.

To the Board of Directors of BreitBurn Energy Company LP (the "Company"):

1) We have evaluated the Company's reserves data as of December 31, 2004. The
reserves data consists of the following:

> (a) Proved and proved plus probable oil and gas reserves
>   estimated as of December 31, 2004, 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 of December 31, 2004, using constant prices and costs and the
>   related estimated future net revenue.

2) 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).

3) 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.

4) 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, 2004, and identifies the
respective portions thereof that we have evaluated, audited and reviewed and
reported on to the Company's management:

|Preparation |                      | Net Present Value
    of Future Net Revenue (CM$)
|----------- | -------------------- | -------------------------------------------------
|Date of     |                      | (before Income Taxes, 10% Discount Rate)         
|Evaluation  |                      |                                                  
|Report      | Location of Reserves | Audited                                          
|            |                      |                                                  
|            | California and       |                                                  
|12-31-2004  | Wyoming,             | -                                                
|            |                      |                                                  

5) In our opinion, the reserves data evaluated by us have, in all material
respects, been determined and are in accordance with the COGE Handbook.

A-3

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6) We have no responsibility to update our report for events and
circumstances occurring after the preparation date.

7) Because the reserves data are based on judgments regarding future events,
actual results will vary and variations may be material.

Executed as to our report referred to above:

NETHERLAND, SEWELL & ASSOCIATES, INC.Houston, Texas, USAMarch 1, 2005By: /s/ J. Carter Henson, Jr.J. Carter Henson, Jr., P.E.Senior Vice President


A-4

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Cawley, Gillespie & Associates, Inc.

|302 FORT WORTH CLUB BUILDING | 1000 LOUISIANA           
|---------------------------- | -------------------------
|306 WEST SEVENTH STREET FORT | SUITE 625                
|WORTH. TEXAS 76102-4SS7      | HOUSTON, TEXAS 77002-5008
|(817) 336-2461               | (713) 651-9944           
|FAX (817) 877-3728           | FAX (713) 651-9980       

March 1,2005

|Mr. Chris Williamson
    BreitBurn Energy |     |                                               
|----------------------------------------- | --- | ----------------------------------------------
|Company LP 515 South
    Flower Street    |     |                                               
|48th Floor
    Los Angeles, CA 90071      |     |                                               
|                                          | Re: | Reserves Compliance
    Letter - Form 51-101F2
|                                          |     | Evaluation Summary                            
|                                          |     | BreitBurn Energy
    Company LP InterestsTotal
|                                          |     | Proved and Probable ReservesEast Coyote and   
|                                          |     | Sawtelle Fields,
    California As of December
|                                          |     | 31.2004                                       

To the board of directors of BreitBurn Energy Company, LP
(the "Company"):

1. In accordance with your request, we have evaluated the
  Company's reserves data as of December 31, 2004. The reserves data consist of
  the following:

> (a) proved and probable oil and gas reserves estimated as
>     of December 31. 2004 using McDaniel 01/01/2005 forecast prices and costs;
>     and the Company's Constant prices and costs; and
>     (b) the related estimated future net revenue, as set
>     forth in our report dated March 1. 2005.

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 "COGEH") prepared
>   jointly by the Society of Petroleum Evaluation Engineers (Calgary Chapter) and
>   the Canadian Institute of Mining. Metallurgy & Petroleum (Petroleum Society).
>   However, the presentation format of our report does not contain certain
>   details suggested by the COGEH,

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 COGEH.
2. The following table sets forth the estimated future net
  revenue (before deduction of taxes) attributed to proved plus probable
  reserves, estimated using McDaniel 01/01/2005 forecast prices and costs and
  the Company's Constant 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, 2004, and identifies the respective portions
  thereof that we have evaluated and reported on to the Company's management:

A-5

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BreitBurn Energy Company LP Reserves 
Compliance Letter East Coyote and Sawtelle Fields, California 
As of December 3 1, 2004

|                       |                  |                          | Total Proved plus Probable 
|---------------------- | ---------------- | ------------------------ | ---------------------------
|                       |                  |                          | Net Present Value of Future
|                       |                  |                          | Net Revenue (before income 
|                       |                  |                          | taxes, 10% discount rate)  
|Description            | Preparation Date |                          |                            
|of Evaluation          | of Report        | Location of Reserves     | Evaluated. MS CND          
|                       |                  |                          |                            
|McDaniel Forecast Case | March 1, 2005    | East Coyote and Sawtelle | 39,953.3                   
|                       |                  | Fields, California, USA  |                            
|                       |                  |                          |                            
|Company Constant Case  | March 1, 2005    | East Coyote and Sawtelle | 59,834.6                   
|                       |                  | Fields, California, USA  |                            

1. In our opinion, the reserves data
  evaluated by us have, in all material respects, been determined and are in
  accordance with the COGEH.
2. We have no responsibility to update our reports referred to in paragraph 4
  for events and circumstances occurring after their respective preparation
  dates.
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:

Cawley, Gillespie & Associates, Inc.Fort Worth, Texas/USAMarch 1,2005Robert D. Ravnaas, P.E.Executive Vice President




A-6

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SCHEDULE B
REPORT OF MANAGEMENT AND DIRECTORS 
ON RESERVES DATA AND OTHER INFORMATIONTerms 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, 2004 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, 2004 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.
B-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. Buchanan               | (Signed) Grant D. Billing
|Chief Executive Officer                   | Director                 
|                                          |                          
|(Signed) David J. Fricker                 | (Signed) Jeffrey T. Smith
|Vice President, Corporate
    Development | Director                 

March 3, 2005

B-2

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SCHEDULE C

AUDIT COMMITTEE INFORMATION

Audit Committee Charter General

Provident Energy Trust (the "Trust") has delegated a number
of duties and responsibilities regarding the management and administration of
the operations and affairs of the Trust to its subsidiary, Provident Energy Ltd.
(the "Corporation") pursuant to the trust indenture, as amended. As such, the
board of directors (the "Board") of the Corporation has oversight
responsibilities, authorities and duties in connection with the business of the
Trust and the Corporation. The Board has delegated the specific oversight
responsibilities, authorities and duties as described below to the Audit
Committee (the "Committee").

For the purpose of these terms of reference, the term "Provident" shall
include the Trust, the Corporation and their subsidiaries.

Authority and Responsibilities

The Committee is part of the Board. Its primary functions are
to assist the Board in fulfilling its oversight responsibilities with respect
to: (i) the review and recommendation for approval of the financial statements
and the financial reporting of the Trust; (ii) the assessment of the system of
internal, accounting and financial reporting controls and procedures that
management has established, including for the purpose of monitoring its
compliance with regulatory requirements; and (iii) the appointment and
compensation of the external auditor and the oversight of the external audit
process. In addition, the Committee shall oversee Provident's: (i) financial
policies and strategies; (ii) financial risk management practices; and (iii)
transactions or circumstances which could materially affect the financial
profile of the Trust.

Management is responsible for establishing and maintaining
controls, procedures and processes and the Committee is appointed by the Board
to oversee, review and monitor those controls, procedures and processes.

The Committee, in its capacity as a committee of the Board
and subject to the rights of unitholders and applicable law, shall be directly
responsible for overseeing the relationship of the external auditor with the
Trust, including the appointment, compensation, retention and oversight of the
work of any external auditor engaged (including resolution of disagreements
between management of Provident and the external auditor regarding financial
reporting) for the purpose of preparing or issuing an audit report or performing
other audit, review or attest services for the Trust. The external auditor shall
report directly to the Committee. The Committee should have a clear
understanding with the external auditor that such external auditor must maintain
an open and transparent relationship with the Committee, and that the ultimate
accountability of the external auditor is to the unitholders of the Trust.

In carrying out its role, the Committee has the following specific
authorities and responsibilities:

> (a) financial information and reporting
>   (i) to review with management and the external auditor, and recommend to
>     the Board for approval, the annual and interim financial statements of the
>     Trust and

C-1

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> related financial reporting, including management's discussion and
>     analysis and earnings press releases;
>     (ii) to review with management and recommend to the Board
>     for approval, any financial statements of the Trust which have not
>     previously been approved by the Board and which are to be included in a
>     prospectus or other public disclosure document of the Trust;
>     (iii) to consider and be satisfied that adequate policies
>     and procedures are in place for the review of the Trust's disclosure of
>     financial information extracted or derived from the Trust's financial
>     statements (other than disclosure referred to in clause (a)(i) above), and
>     periodically assess the adequacy of such procedures;
>   (b) internal controls
>   (i) to review the internal control staff functions including:
>     (1) the purpose, authority and organizational reporting lines, and
>       (2) the annual audit plan, budget and staffing thereof;
>     (ii) to review, with the Vice President, Finance, Chief
>     Financial Officer and Corporate Secretary (the "CFO"), controller or others,
>     as appropriate, Provident's internal system of audit controls and the
>     results of internal audits;
>     (iii) to establish procedures for:
>     (1) the receipt, retention and treatment of any complaint regarding
>       accounting, internal accounting controls or auditing matters; and
>       (2) the confidential, anonymous submissions by employees of concerns
>       regarding questionable accounting or auditing matters;
>   (c) external audit
>   (i) to evaluate the services provided by the external auditor and
>     recommend to the Board, if necessary, the replacement of the external
>     auditor;
>     (ii) to pre-approve or approve (if pre-approval is not
>     required by law) the appointment of the external auditor to provide, and the
>     fees related to, any audit service or non-prohibited non-audit service and,
>     if desired, establish detailed policies and procedures for the pre-approval
>     of audit services and non-prohibited non-audit services by the external
>     auditor. The Committee may delegate this ability to one or more members of
>     the Committee to the extent permitted by applicable law, provided that any
>     pre-approvals granted pursuant to such delegation must be detailed as to the
>     particular service to be provided, may not delegate Committee
>     responsibilities to management of Provident and must be reported to the full
>     Committee at its next scheduled meeting;
>     (iii) to obtain and review at least annually a written report by the
>     external auditor setting out the auditor's internal quality-control
>     procedures, any material issues

C-2

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> raised by the auditor's internal quality-control reviews and the steps
>     taken to resolve those issues;
>     (iv) to review and discuss with the external auditor all
>     relationships that the external auditor and its affiliates have with the
>     Trust and its affiliates in order to determine the external auditor's
>     independence, including, without limitation:
>     (1) requesting, receiving and reviewing, on a periodic
>       basis but at least annually, a formal written statement from the external
>       auditor delineating all relationships that may reasonably be thought to
>       bear on the independence of the external auditor with respect to
>       Provident,
>       (2) discussing with the external auditor any disclosed
>       relationships or services that the external auditor believes may affect
>       the objectivity and independence of the external auditor, and
>       (3) recommending that the Board take appropriate action
>       in response to the external auditor's report to satisfy itself of the
>       external auditor's independence;
>     (v) to review the audit plan of the external auditor prior to the
>     commencement of the audit;
>     (vi) to review and approve the hiring policies of
>     Provident regarding partners and employees and former partners and employees
>     of the present and former external auditor of the Trust;
>     (vii) to obtain assurance from the external auditor that
>     disclosure to the Committee is not required pursuant to the provisions of
>     the United States Securities Exchange Act of 1934, as amended,
>     regarding the discovery of any illegal acts by the external auditor;
>     (viii) to review and discuss a report from the external auditor at least
>     quarterly regarding:
>     (1) all critical accounting policies and practices to be used,
>       (2) all alternative treatments within generally
>       accepted accounting principles for policies and practices related to
>       material items that have been discussed with management, including the
>       ramifications of the use of such alternative disclosures and treatments,
>       and the treatment preferred by the external auditor, and
>       (3) other material written communications between the
>       external auditor and management, such as any management letter or schedule
>       of unadjusted differences;
>   (d) risk management
>   to review and monitor Provident's major financial risks and risk management
>   policies and the steps taken by management to mitigate those risks; and

C-3

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> (e) compliance
>   to review Provident's financial reporting procedures and
>   policies to ensure compliance with all legal and regulatory requirements and
>   to investigate any non-adherence to those procedures and policies.

Composition and Procedures

> (a) Size
>   The Committee will consist of a minimum of three directors.
>   The members of the Committee are appointed by the Board. Each member shall
>   serve until his or her successor is appointed, unless he shall resign or be
>   removed by the Board or he shall otherwise cease to be a director of the
>   Corporation. The Board shall fill any vacancy if the membership of the
>   Committee is less than three directors.
>   The Chair of the Committee may be designated by the Board
>   or, if it does not do so, the members of the Committee may elect a Chair by
>   vote of a majority of the full Committee membership.
>   (b) Qualifications
>   All members of the Committee must satisfy the independence,
>   financial literacy and experience requirements of applicable Canadian and
>   United States securities laws, rules and guidelines, any applicable stock
>   exchange requirements or guidelines and any other applicable regulatory rules.
>   In particular: (i) each member shall be "independent" and "financially
>   literate" within the meaning of Multilateral Instrument 52-110 "Audit
>   Committees", (ii) at least one member must be "financially sophisticated"
>   under the rules of the American Stock Exchange, and (iii) at least one member
>   must be an "audit committee financial expert" within the meaning of that term
>   under the United States Securities Exchange Act of 1934, as amended and
>   the rules adopted by the United States Securities and Exchange Commission
>   thereunder.
>   Members of the Committee may not, other than in their
>   respective capacities as members of the Committee, the Board or any other
>   committee of the Board, accept directly or indirectly any consulting, advisory
>   or other compensatory fee from Provident, or be an "affiliated person" (as
>   such term is defined in the United StatesSecurities Exchange Act of 1934,
>   as amended, and the rules adopted by the United States Securities and Exchange
>   Commission thereunder) of Provident. For greater certainty, director's fees,
>   options and similar compensation arrangements and fixed amounts of
>   compensation under a retirement plan (including deferred compensation) for
>   prior service with Provident that are not contingent on continued service
>   should be the only compensation a Committee member receives from Provident.
>   (c) Meetings
>   Meetings of the Committee shall be conducted as follows:
>   (i) the Committee shall meet at least quarterly at such
>     times and at such locations as the Chair of the Committee shall determine,
>     provided that meetings shall be scheduled so as to permit timely review of
>     the Trust's quarterly and annual

C-4

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financial statements and related management's discussion
    and analysis. The external auditor or any two members of the Committee may
    also request a meeting of the Committee. The Chair of the Committee shall
    hold in camera sessions of the Committee, without management present,
    at every meeting;

> (ii) the quorum for meetings shall be a majority of the
>     members of the Committee, present in person or by telephone or by other
>     telecommunication device that permits all persons participating in the
>     meeting to hear each other;
>     (iii) if the Chair of the Committee is not present at any
>     meeting of the Committee, one of the other members of the Committee who is
>     present at the meeting shall be chosen by the Committee to preside at the
>     meeting;
>     (iv) the Chair shall, in consultation with management and
>     the external auditor, establish the agenda for the meetings and instruct
>     management to ensure that properly prepared agenda materials are circulated
>     to the Committee with sufficient time for study prior to the meeting;
>     (v) every question at a Committee meeting shall be decided by a majority
>     of the votes cast;
>     (vi) the Chief Executive Officer (the "CEO"), the
>     President and the CFO shall be available to advise the Committee, shall
>     receive notice of meetings and may attend meetings of the Committee at the
>     invitation of the Chair of the Committee. Other management representatives,
>     other Board members, officers or employees of Provident, the external
>     auditor, outside counsel and other experts or consultants may be invited to
>     attend as necessary;
>     (vii) the Chair shall appoint a secretary for the purpose of recording
>     the minutes of each meeting; and
>     (viii) notice of the time and place of every meeting
>     shall be given in writing (including by way of written facsimile
>     communication or email) to each member of the Committee at least 24 hours
>     prior to the time fixed for such meeting, provided, however, that a member
>     may in any manner waive a notice of a meeting; and attendance of a member at
>     a meeting constitutes a waiver of notice of the meeting, except where a
>     member attends a meeting for the express purpose of objecting to the
>     transaction of any business on the ground that the meeting is not lawfully
>     called. Notice of every meeting shall also be provided to the external
>     auditor.
>   The Committee shall provide the Board with a summary of all
>   meetings together with a copy of the minutes from such meetings. Where minutes
>   have not yet been prepared, the Chair shall provide the Board with oral
>   reports on the activities of the Committee. All information reviewed and
>   discussed by the Committee at any meeting shall be referred to in the minutes
>   and made available for examination by the Board upon request to the Chair.
>   (d) Review of Financial Statements
>   The Committee will review the Trust's annual audited financial statements
>   and interim financial statements and the related management's discussion and
>   analysis with the CEO

C-5

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> and CFO and then recommend that the Board approve such
>   financial statements and management's discussion and analysis. The controller
>   and the external auditor will be present at these meetings.
>   (e) Review of CEO and CFO Certification Process
>   In connection with its review of the annual audited
>   financial statements and interim financial statements, the Committee will also
>   review the process for the CEO and CFO certifications with respect to the
>   financial statements and Provident's disclosure and internal controls,
>   including any material deficiencies or changes in those controls. The
>   Committee will review with the CEO, the CFO and the external auditor: (i) all
>   significant deficiencies and material weaknesses in the design or operation of
>   Provident's internal control over financial reporting which could adversely
>   affect Provident's ability to record, process, summarize and report financial
>   information required to be disclosed by the Trust in the reports that it files
>   or submits under the United States Securities Exchange Act of 1934, as
>   amended, within the required time periods, and (ii) any fraud, whether or not
>   material, that involves management of Provident or other employees who have a
>   significant role in Provident's internal control over financial reporting.
>   (f) Review of Earnings and Other Releases
>   The Committee will review with the CFO any news release
>   containing financial information taken from Provident's financial statements
>   prior to the release of such news release to the public. In addition, the CFO
>   must review with the Committee the substance of any presentations to analysts
>   or rating agencies that contain a change in strategy or outlook.
>   (g) The Trust's External Auditor
>   The Committee shall meet with the external auditor, as the
>   Committee may deem appropriate, to consider any matter which the Committee or
>   external auditor believes should be brought to the attention of the Board or
>   the unitholders of the Trust.
>   (h) Audit Partner Rotation
>   The Committee will ensure the rotation of partners on the
>   audit engagement team of the external auditor in accordance with applicable
>   law. The Committee will also periodically consider whether, in order to assure
>   continuing external auditor independence, it is appropriate to adopt a policy
>   of rotating the external auditing firm on a regular basis.
>   (i) Audit Partner Review
>   The Committee will review and evaluate the lead partner of the external
>   auditor.
>   (j) Access to Independent Advisors
>   The Committee may at any time retain outside financial,
>   legal or other advisors as it determines necessary to carry out its duties, at
>   the expense of Provident. Provident shall provide for appropriate funding, as
>   determined by the Committee in its capacity as a committee of the Board, for
>   payment of: (i) compensation to the external auditor for the purpose of
>   preparing or issuing an audit report or performing other audit, review or
>   attest

C-6

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> services for the Trust, (ii) compensation to any advisors
>   employed by the Committee and (iii) ordinary administrative expenses of the
>   Committee that are necessary or appropriate in carrying out its duties.
>   (k)

The Committee shall review and reassess the adequacy of this Charter at
  least annually or otherwise, as it deems appropriate, and propose recommended
  changes to the Board.

(l)

The Committee shall report regularly to the Board about any
  issues that arise with respect to the quality or integrity of the Trust's
  financial statements, Provident's compliance with legal or regulatory
  requirements, the performance and independence of the external auditor, or the
  internal audit function.

C-7

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Appendix A to Schedule C

AUDIT COMMITTEE ANNUAL CALENDAR 
(December 31 year end)

Quarterly Audit Committee Meetings: May, August and November

- Approval of quarterly financial statements

> MD&A;
>     Press release;
>     Estimates and management judgments;
>     Review of report from external auditor;

- Management certification process with report from CEO/CFO and processes
  followed.

> Other standard items including management reporting on:
>   Material communication with rating agencies;
>     Material legal matters/litigation;
>     Analyst reports.

- Report from Audit Committee Chair on pre-approvals for audit, non-audit,
  review or attestation assignments.
- In camera review with external auditor.

February or March Meeting to Review Audited Financial Statements

- Review annual financial statements, MD&A and related disclosure.
- Discuss significant accounting policies.
- Discuss critical estimates, and judgments and impact on statements.
- Review business risks disclosure in MD&A.
- Receive external auditor's report on statutory audit and various matters
  where external auditor is required to report, such as:

> auditor independence;
>     methods used to account for significant unusual transactions;
>     material proposed audit adjustments and immaterial adjustments not
>     recorded by management;

C-8

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> auditor judgments about the quality of the Company's accounting
>     principles;
>     management-related issues encountered in performing the audit;
>     disagreements with management over the application of accounting
>     principles, management's accounting estimates and related matters.

- Review management's "internal control report"
  to be included in annual report and external auditor's assessment of same.
- Internal control issues, if any.
- Separate in camera meetings with the
  external auditor and external counsel.
- Annual information form and comparable 40-F.
- Public disclosure relevant to
  Audit Committee, such as re-appointment of auditor, disclosure of pre-approval
  procedures as required by SEC Auditor Independence Rules and disclosure
  relating to financial experts.

October/November Meeting

- Discuss annual audit plan including scope of
  engagement and related matters

> audit team and potential rotation;
>     review and consideration of budgeted audit fees;
>     special areas for concentration by external audit.

- Review preparations for production of
  "internal control report" for annual report.
- Review Audit Committee charter and report to
  Board.
- Review and affirmation of principles for
  pre-approval of audit, non-audit, review and attestation services.

Special issues to be dealt with at one or more regular meetings or through a
special meeting of the Audit Committee

- Educational component to Audit Committee
  functions:

> critical accounting
>     policies/estimates/general discussion;
>     treasury activities;
>     internal control risks:
>     support to CEO/CFO certification
>     financing vehicles, loan documents and applicable covenant patterns;

C-9

---



> taxation issues and tax planning;
>     new developments such as:
>     non-GAAP earnings measures;
>       identification of financial experts;
>     competitors and accounting issues involving competitors;
>     preparing of Audit Committee effectiveness report for Board
>     of Directors;
>     business risks and related oversight responsibilities of
>     Audit Committee including applicable procedures:
>     earnings guidances;
>     pro forma reporting;
>       selective disclosure policy;

- Review and consideration of
  succession planning and related issues with respect to Audit Committee Chair
  and Audit Committee members in light of independence requirements and
  financial expertise requirements:

> communication with the Corporate Governance Committee as may
>     be required;

- Review of complaints received and
  outcome of investigation.

These educational elements may be dealt with at a special annual
meeting of the Committee.

C-10

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SCHEDULE D
AUDITED ANNUAL CONSOLIDATED FINANCIAL STATEMENTS 
OF OLYMPIA ENERGY INC.
AUDITOR'S REPORTTo the Shareholders of Olympia Energy Inc.
We have audited the consolidated balance sheets of Olympia
Energy Inc. as at December 31, 2003 and 2002 and the consolidated statements of
earnings and retained earnings and cash flows for the years then ended. These
financial statements are the responsibility of the Company's management. 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 Company
as at December 31, 2003 and 2002 and the results of its operations and its cash
flows for the years then ended in accordance with Canadian generally accepted
accounting principles.

|March 5, 2004 | (Signed) PricewaterhouseCoopers LLP
|------------- | -----------------------------------
|              | PricewaterhouseCoopers LLP         
|              | Chartered Accountants              

D-1

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CONSOLIDATED BALANCE SHEETS

|                                         |             |            
|---------------------------------------- | ----------- | -----------
|As at December 31,                       | 2003        | 2002       
|                                         |             |            
|ASSETS                                   | $           | $          
|Current assets                           |             |            
|Cash                                     | 1,870       | 313,424    
|Accounts receivable                      | 8,714,468   | 7,519,947  
|Investment in High Point Energy Corp.    | 10,142      | 213,745    
|Inventory                                | -           | 180,081    
|Prepaid expenses                         | 486,307     | 472,947    
|                                         | 9,212,787   | 8,700,144  
|Property and equipment(note 2)           | 145,894,817 | 110,307,179
|                                         | 155,107,604 | 119,007,323
|                                         |             |            
|LIABILITIES                              |             |            
|Current liabilities                      |             |            
|Accounts payable and accrued liabilities | 18,003,826  | 12,480,274 
|Bank debt (note 3)                       | 43,170,590  | 30,268,978 
|                                         | 61,174,416  | 42,749,252 
|Future site restoration and abandonment  | 1,464,474   | 1,135,220  
|Future income taxes (note 6)             | 33,241,175  | 31,151,700 
|                                         | 95,880,065  | 75,036,172 
|                                         |             |            
|SHAREHOLDERS' EQUITY                     |             |            
|Capital stock(note 4)                    | 22,574,061  | 20,250,719 
|Retained earnings                        | 36,653,478  | 23,720,432 
|                                         | 59,227,539  | 43,971,151 
|                                         | 155,107,604 | 119,007,323

|                               |                      
|------------------------------ | ---------------------
|Signed on behalf of the Board: |                      
|                               |                      
|                               |                      
|(Signed) Peter Salamon         | (Signed) Brian Mellum
|Director                       | Director             

D-2

---



CONSOLIDATED STATEMENTS OF EARNINGS AND RETAINED EARNINGS

|For the years ended December 31,                                 | 2003        | 2002       
|---------------------------------------------------------------- | ----------- | -----------
|                                                                 |             |            
|                                                                 |             |            
|REVENUES                                                         | $           | $          
|Petroleum and natural gas
    revenue                            | 48,418,102  | 34,928,190 
|Royalties                                                        | (8,866,150) | (5,667,562)
|                                                                 | 39,551,952  | 29,260,628 
|EXPENSES                                                         |             |            
|Production Expenses                                              | 8,532,013   | 7,868,422  
|General and administrative - net
    of recoveries               | 3,511,101   | 2,838,040  
|Interest on bank debt                                            | 1,706,790   | 1,745,195  
|Depletion and depreciation                                       | 13,324,357  | 13,326,258 
|                                                                 | 27,074,261  | 25,777,915 
|Gain on sale of High Point
    shares                            | 1,087,049   | -          
|Earnings before income taxes                                     | 13,564,740  | 3,482,713  
|Income tax expense(note 6)                                       |             |            
|Current                                                          | 458,119     | 676,023    
|Future                                                           | 109,865     | 78,151     
|                                                                 | 567,984     | 754,174    
|Net Earnings for the year                                        | 12,996,756  | 2,728,539  
|Retained earnings - Beginning of
    year                        | 23,720,432  | 20,991,893 
|Excess of assigned value-repurchase of common
    stock (note 4) | (63,710)    | -          
|Retained earnings - End of Year                                  | 36,653,478  | 23,720,432 

Per share information(note 5)



---

CONSOLIDATED STATEMENTS OF CASH FLOWS

|                                                        |              |             
|------------------------------------------------------- | ------------ | ------------
|For the years ended December 31,                        | 2003         | 2002        
|                                                        |              |             
|CASH PROVIDED BY (USED IN):                             | $            | $           
|OPERATING ACTIVITIES                                    |              |             
|Net earnings for the year                               | 12,996,756   | 2,728,539   
|Items not affecting cash:                               |              |             
|Gain on sale of
    High Point shares                   | (1,087,049)  | -           
|Future income taxes                                     | 109,865      | 78,151      
|Depletion and depreciation                              | 13,324,357   | 13,326,258  
|Cash flow from operations                               | 25,343,929   | 16,132,948  
|Change in non-cash operating working capital            | (2,011,437)  | 2,304,428   
|                                                        | 23,332,492   | 18,437,376  
|INVESTING ACTIVITIES                                    |              |             
|Property and equipment additions                        | (48,844,994) | (26,218,858)
|Proceeds on sale of property and
    equipment          | 262,253      | 7,580,069   
|Proceeds on sale of High Point
    shares               | 1,290,652    | -           
|Change in non-cash investing working capital            | 6,507,189    | 249,833     
|                                                        | (40,784,900) | (18,388,856)
|FINANCING ACTIVITIES                                    |              |             
|Issue of capital stock - net                            | 4,316,992    | 5,864,996   
|Excess of assigned value -
    normal course issuer bid | (77,750)     | -           
|Increase (Decrease) in bank debt                        | 12,901,612   | (5,683,107) 
|                                                        | 17,140,854   | 181,889     
|(Decrease) Increase in cash                             | (311,554)    | 230,309     
|Cash - Beginning of year                                | 313,424      | 83,115      
|Cash - End of year                                      | 1,870        | 313,424     
|Supplemental information                                |              |             
|Income tax paid                                         | 1,701,860    | 692,831     
|Interest paid                                           | 1,545,175    | 1,654,313   

D-4

---



Notes to the Consolidated Financial Statements For the years
ended December 31,2003 and 2002

1.

The Company is engaged in the exploration for and the production of petroleum
and natural gas in Western Canada.

These financial statements are prepared in accordance with Canadian generally
accepted accounting principles within the framework of the accounting policies
described below:

Consolidation

The consolidated financial statements include the accounts of the Company and
its wholly owned subsidiary Olympia Acquisition Inc.

The consolidated financial statements for 2002 include the
accounts of the Company and its wholly owned subsidiaries, Olyco Resources Inc.
("Olyco"), acquired in 1999, Olyco Resources II Inc. ("Olyco II") acquired in
2000 and Bridgetown Energy Corporation ("Bridgetown") and Olympia Acquisition
Corporation acquired in 2001. All of these corporations except Olympia
Acquisition Corporation were formally amalgamated with Olympia Energy Inc. on
January 1, 2003.

Revenue Recognition

Revenues associated with sales of crude oil, natural gas and natural gas
liquids are recognized when the title passes to the purchaser.

Future Income Taxes

The Company follows the liability method of accounting for
income taxes. Under this method, future income tax is based on the differences
between assets and liabilities reported for financial accounting purposes and
those reported for income tax purposes.

Future income taxes are calculated by reference to income tax rates and laws
that have been enacted and that will be in effect when the differences are
expected to reverse.

The effect of future tax assets and liabilities on a change in income tax
rates is recognized in the period in which the change occurs.

Cash and Cash Equivalents

Cash and cash equivalents include cash and short-term investments with a
maturity of three months or less when purchased.

Petroleum and Natural Gas Properties

The Company follows the full-cost method of accounting
whereby all, costs related to the acquisition, exploration and development of
petroleum and natural gas properties, net of government incentives, are
capitalized. Such costs include lease acquisition costs, geological and
geophysical expenditures, costs of drilling both productive and non-productive
wells and related plant and production equipment costs. No carrying costs or
corporate costs are capitalized.



---

Proceeds on disposition of petroleum and natural gas
properties are accounted for as a reduction of capitalized costs with no gains
or losses recognized unless such disposition results in a change of 20 percent
or more in the depletion rate.
Ceiling Test
The net amount at which petroleum and natural gas properties are carried is
subject to a cost recovery test (the "ceiling test").
The ceiling test is computed by comparing the ultimate
recoverable amount from future net reserves as determined by independent
engineers using proved reserves and period end prices, less future removal and
site restoration costs, overhead, financing costs and income taxes to the net
carrying costs of petroleum and natural gas properties.
Depletion and Depreciation
Depletion and depreciation of petroleum and natural gas
properties are computed using the unit-of-production method where the ratio of
current year production to proven reserves before royalties as determined by
independent engineers in accordance with National Instrument 51-101, determines
the proportion of the depletion base to be expensed.
Unproved properties are excluded from the depletion base until it is
determined whether proved reserves are attributable to the properties or
impairment occurs.
Gas reserves and production are converted to barrels of crude oil on a heat
equivalent basis (6:l).
In determining the depletion base, the Company includes total
net capitalized costs plus the future costs to be incurred in developing proven
reserves as well as the estimated cost of site restoration and abandonment less
salvage values and excludes the cost of undeveloped land.
Depreciation on furniture and fixtures is provided over its useful lives
using the declining balance method at an annual rate of 25 percent.
Joint Ventures
A significant portion of the Company's exploration and production activities
are conducted jointly with others and the financial statements reflect only the
Company's proportionate interest in such activities.
Flow-Through Shares
The resource expenditure deductions for income tax purposes
related to exploratory and development activities funded by flow-through share
arrangements are renounced to investors in accordance with income tax
legislation. Future income tax liabilities and share capital are adjusted by the
estimated cost of the renounced income tax deductions when the related
flow-through expenditures are made.
Stock Based Compensation
In 2002, the Company adopted CICA Handbook section 3870
entitled "Stock Based Compensation and Other Stock Based Payments". It did so by
disclosing the pro forma impact on net income and earnings per share by using
the fair-value method and not to recognise compensation in the accounts for
stock option awards after January 1, 2002.D-6

---

The consideration paid by employees on the exercise of stock options is
credited to share capital.
Future Site Restoration and Abandonment Provision
The provision for future removal and site restoration costs,
related to petroleum and natural gas operations, is based on estimates made by
the Company and is charged against income on a unit-of-production basis as part
of depletion expense. The cumulative amount has been recorded as future site
restoration and abandonment provision.
Financial Instruments
The Company uses financial instruments and physical delivery
commodity contracts from time to time to protect future earnings and cash flows
from the potential impact of fluctuating commodity prices and not for
speculative purposes. Gains or losses on these contracts are included in
revenues at the time the underlying commodity is sold or when the positions are
settled.
Measurement Uncertainty
Amounts recorded for depreciation and depletion, the
provision for future site restoration and abandonment costs and amounts used for
ceiling test calculations are based on estimates of oil and natural gas
reserves. The Company's reserve estimates are reviewed annually by its
independent engineering firm. By their nature, these estimates of reserves and
future cash flows are subject to measurement uncertainty, and the impact on the
financial statements of future periods could be material.
Per Share Amounts
The Company uses the treasury stock method to determine the
dilutive effect of stock options and other dilutive instruments. This method
assumes that proceeds received from the exercise of in-the-money stock options
and other dilutive instruments are used to purchase common shares at the average
market price during the year.
Inventory
Inventory in 2002 comprised surplus equipment for resale and
is recorded at the lower of cost or expected net realisable value. During 2003
the majority of these items were either sold or were transferred to petroleum or
natural gas properties.
Investment in High Point Resources Inc.
At December 31,2002 the Company owned 812,018 shares which
represented 2.1 percent of the outstanding share capital of High Point at that
date. This investment is carried at cost. The fair market value at December 31,
2002 was $1,258,629.
During 2003, the Company sold 773,488 of these shares for
total gross proceeds of $1,290,651. A gain of $1,087,049 was recorded on the
sale based on the average cost of such shares. The Company continues to hold
38,530 shares for resale with a cost of $10,142. The fair market value at
December 31, 2003 is $99,407.D-7

---

2.Property and
equipment

|                                                   | 2003         | 2002        
|-------------------------------------------------- | ------------ | ------------
|                                                   | $            | $           
|Petroleum and natural gas properties and equipment | 204,137,269  | 155,571,717 
|Furniture, fixtures and other                      | 1,077,573    | 1,104,170   
|                                                   | 205,214,842  | 156,675,887 
|Less: Accumulated depletion and depreciation       | (59,320,025) | (46,368,708)
|                                                   | 145,894,817  | 110,307,179 

At December 31, 2003 costs of $7,433,673 (2002 - $10,897,514)
with respect to unproved properties have been excluded from costs subject to
depletion. No overhead charges have been capitalized to petroleum and natural
gas properties.

As at December 31, 2003, the total estimated future site
restoration costs to be accrued over the remaining life of the Company's proven
reserves were estimated to be $4,495,200. Site restoration expense of $329,254
was accrued for the year ended December 31, 2003. Actual site restoration costs
incurred in 2003 were $135,801 (2002 - $10,569).

3. Bank Debt

|                            | 2003       | 2002      
|--------------------------- | ---------- | ----------
|                            | $          | $         
|Revolving demand bank loan* | 43,170,590 | 30,268,978

*Bank prime rate plus varying rates from 0% to 1% adjusted quarterly and
dependent on the Company's debt to cash flow ratio (or at the bankers'
acceptance rate plus stamping fee)

In 2002, the Company implemented the Canadian Institute of
Chartered Accountants (CICA) Emerging Issues Abstract EIC #122 for the
classification of callable debt on the balance sheet. This required that all of
the Company's debt be classified as current debt.

The Company's credit facilities included a revolving demand
bank loan facility with a credit limit of $50,000,000 (2002 - $40,000,000)
together with a non-revolving acquisition/development demand loan facility of
$5,000,000 and a treasury risk facility of $500,000.

The terms of the non-revolving acquisition/development demand
loan facility specify an interest rate of bank prime plus three quarters of a
percent and that monthly payments must be made over the engineering half life of
the reserves being financed. No amounts have been drawn against this facility.

The treasury risk facility is repayable as the related contracts mature, and
has a maximum term of forty-eight months. No amounts have been drawn against
this facility.

Security for these facilities includes a floating charge
debenture in the amount of $75,000,000 issued by the Company and a negative
pledge and undertaking to provide a fixed charge on the Company's major
producing properties.

As at December 31, 2003 and 2002 the Company was in compliance with all the
covenants under its bank credit facilities.

D-8

---



4. Capital stock

Authorized

Unlimited number of Common Shares without nominal or par value

Unlimited number of 6.5 percent Cumulative Non-Voting Preferred Shares

Common Shares: Issued

|                                  | 2003       | 2002       
|--------------------------------- | ---------- | -----------
|                                  | Number of  |            
|                                  | shares     | Amount $   
|Balance - December 31             | 39,174,194 | 20,250,719 
|Flow-through shares issued        | 1,066,666  | 3,999,998  
|Normal Course Issuer Bid          | (30,000)   | (14,040)   
|Stock options exercised           | 700,300    | 584,996    
|Share issuance costs              | -          | (167,850)  
|Tax effect of flow-through shares | -          | (2,079,762)
|                                  | 40,911,160 | 22,574,061 

Stock Options

Pursuant to the terms of the 1996 Incentive Stock Option Plan
No. 1 (the "Plan"), the exercise price of each stock option may not be less than
the weighted average price of the common shares during the five trading days
preceding the date of grant of the option. The stock options may be issued for
terms of up to 10 years and may vest over such periods as the Company's board of
directors in its discretion may prescribe.

At December 31, 2003, 2,197,700 (2002 1,578,500) options were outstanding of
which 603,700 (2002 - 981,500) were fully vested at an average exercise price of
$2.12 ($1.10 in 2002).

975,333 (2002 - 44,833) options remained available to be
granted pursuant to the Plan. An amendment to the plan that added 2,250,000
stock options to the plan was approved by the shareholders of the Company on May
17, 2003.

A summary of the status of the Company's Stock Option Plan as of December
31,2003 and 2002 and changes during the years ending on those dates is:

|                               | 2003      | 2002     
|------------------------------ | --------- | ---------
|                               |           | Weighted-
|                               |           | average  
|                               |           | exercise 
|Stock Options                  | Shares    | price    
|                               |           | $        
|Outstanding- Beginning of year | 1,578,500 | 1.42     
|Granted                        | 1,345,000 | 2.86     
|Exercised                      | (700,300) | 0.84     
|Forfeited                      | (25,500)  | 2.55     
|Outstanding - End of year      | 2,197,700 | 2.48     

The following table summarises information about stock options outstanding at
December 31, 2003:



---



|               |                   |                  |                 
|-------------- | ----------------- | ---------------- | ----------------
|Range of       | Number            | Weighted-average | Weighted-average
|exercise price | outstanding       | remaining life   | exercise price  
|$              | December 31, 2003 | years            | ($/share)       
|1.01-1.50      | 41,700            | 1.59             | 1.37            
|1.51-2.00      | 668,000           | 1.77             | 1.81            
|2.01-3.00      | 1,040,000         | 3.66             | 2.65            
|3.01-3.50      | 448,000           | 3.06             | 3.17            
|               | 2,197,700         | 2.94             | 2.48            

The aggregate fair value of the 1,345,000 (2002 - 465,000) stock options
granted during the year was computed to be $1,697,640 (2002 - $521,900) or $1.26
(2002 - $1.12) per stock option granted.

The fair value of stock options was determined using the
Black-Scholes Option Pricing Model. Pro forma information regarding net income
is required and has been determined as if the Company has accounted for its
employee stock options granted after December 31, 2001 using the fair value
method. The fair value for these options was estimated at the date of grant
using a Black-Scholes Option Pricing Model with the following assumptions:

|                                                      | 2003 | 2002
|----------------------------------------------------- | ---- | ----
|Volatility factor of expected market price            | .60  | .65 
|Weighted average risk-free
    interest rate (%)      | 3.79 | 4.17
|Dividend yield (%)                                    | -    | -   
|Weighted average expected life of options
    (years) | 3.0  | 4.0 

For purposes of pro forma disclosures, the estimated fair
value of options awarded after January 1, 2002 was amortized to expense over the
options' vesting periods. Had the amortization been booked to the accounts for
the year ended December 31, 2003, earnings would have been reduced by $454,785
(2002 - $172,254) and the basic and diluted earnings per share figures would
have been reduced by $0.01 and $0.01 (2002 - $0.005 and $0.004) respectively.

Normal course issuer bids

On January 29, 2003 the Company announced that it had
initiated a normal course issuer bid that would allow it to purchase for
cancellation up to 3,000,000 common shares. This normal course issuer bid
expired on January 28, 2004. A total of 30,000 common shares were purchased in
2003 pursuant to this normal course issuer bid.

On February 9, 2004 the Company announced that it had
initiated a normal course issuer bid that would allow it to purchase for
cancellation up to 3,000,000 common shares. No common shares have been purchased
pursuant to this normal course issuer bid.

Purchases made pursuant to the normal course issuer bid were
made on the open market and were subject to securities regulations relative to
such transactions which require, among other things, that purchased shares be
cancelled and returned to treasury.

Flow-through shares

On December 24, 2003, the company issued 1,066,666
flow-through shares at $3.75 per share. The resource expenditure deductions for
income tax purposes relative to the exploratory and development activities
funded by this issuance were renounced to the investors in 2003. On December 19,
2002, the company issued 1,434,363 flow-through shares at $4.10 per share. The
resource expenditure deductions



---

for income tax purposes relative to the exploratory and development
activities funded by this issuance were renounced to the investors in 2002.
5. Per share information

|                                                   | 2003        | 2002      
|-------------------------------------------------- | ----------- | ----------
|                                                   | $           | $         
|Net earnings per share                             | 0.33        | 0.07      
|Net earnings per share diluted                     | 0.33        | 0.07      
|Weighted-average number of shares                  | 39,358,077  | 37,967,320
|Diluted number of shares                           | 39,904,555  | 38,753,004
|                                                   |             |           
|                                                   | 2003        | 2002      
|                                                   | $           | $         
|Weighted average common shares outstanding - basic | 39,358,077  | 37,967,320
|Effect of in-the-money stock options               | 1,749,700   | 1,548,500 
|Estimated common shares purchased                  | (1,203,222) | (762,816) 
|Diluted number of shares outstanding               | 39,904,555  | 38,753,004

6. Income taxes

(a) At December 31,2003 the Company has exploration and
development expenditures and undepreciated capital costs totalling $50,285,012
(2002 - $34,060,696) which may be carried forward indefinitely to reduce future
taxable income. The estimated expenditures are as follows:

|                                                 | $         
|------------------------------------------------ | ----------
|Cumulative Canadian oil and gas property expense | 7,177,446 
|Cumulative Canadian development
    expense      | 15,483,940
|Cumulative Canadian exploration
    expense      | 3,340,220 
|Undepreciated capital cost                       | 23,648,879
|Other                                            | 634,527   
|                                                 | 50,285,012

(b) The following reconciles the difference between income tax recorded and
the expected tax expense obtained by applying the expected tax rate to income
before taxes:

|                                                                      | 2003        | 2002       
|--------------------------------------------------------------------- | ----------- | -----------
|                                                                      | $           | $          
|Earnings before income taxes                                          | 13,564,740  | 3,482,713  
|Expected tax at combined federal
    and provincial statutory rate of | 5,526,275   | 1,471,098  
|40.74% (2001 - 42.24%)                                                |             |            
|Crown royalties                                                       | 2,249,925   | 1,944,828  
|Resource allowance                                                    | (2,596,540) | (2,094,692)
|Alberta Royalty Tax Credit                                            | (203,700)   | (193,571)  
|Tax rate changes on future
    income taxes                           | (5,006,035) | (347,100)  
|Non-taxable portion of capital
    gain                               | (221,422)   | -          
|Other                                                                 | 77,498      | (158,389)  
|Large corporations tax                                                | 285,983     | 132,000    
|Provision for Bridgetown assessment                                   | 456,000     | -          
|Tax provision                                                         | 567,984     | 754,174    

D-11

---



|                                                           |         |        
|---------------------------------------------------------- | ------- | -------
|The provision for taxes is comprised of the
    following: |         |        
|Large corporations tax                                     | 285,983 | 132,000
|Current income tax                                         | 172,136 | 544,023
|Future income tax                                          | 109,865 | 78,151 
|                                                           | 567,984 | 754,174

Provision has been made for a proposed reassessment of
Bridgetown Energy Corporation tax returns in respect of transactions prior to
its acquisition by Olympia Energy Inc. The proposed reassessment will be
vigorously defended by the Company and it is premature to speculate on the
actual settlement amount.

(c) The following table summarizes the tax effect of temporary differences
that give rise to the future income tax liability:

|                                                                  | 2003       | 2002      
|----------------------------------------------------------------- | ---------- | ----------
|                                                                  | $          | $         
|Future income tax liabilities:                                    |            |           
|Carrying
    value of capital assets in excess of tax liabilities | 33,985,299 | 31,662,885
|Future income tax assets:                                         |            |           
|Site
    restoration                                              | 507,001    | 358,615   
|Share issue
    costs                                             | 237,123    | 152,570   
|Other                                                             | -          | -         
|                                                                  | 744,124    | 511,185   
|Net future income tax liability                                   | 33,241,175 | 31,151,700

7.

The Company's financial instruments recognized on the balance
sheets consist of cash, accounts receivable, accounts payable and accrued
liabilities and bank debt. The fair value of all financial instruments
classified as current assets or current liabilities approximate their carrying
amounts due to the short-term maturity of these instruments.

A portion of the Company's accounts receivable are from joint
venture partners in the oil and gas industry and are subject to normal industry
credit risk. Purchasers of the Company's petroleum and natural gas products are
subject to an internal credit review designed to mitigate the risk of
non-payment and the carrying value reflects management's assessment of the
associated credit risks.

The nature of the Company's operations results in exposure to fluctuations in
commodity prices. Periodically, the Company enters into certain contracts to
reduce its exposure to such risks.

The Company has a natural gas put option for 4,000 gigajoules
(GJs) per day for January through March of 2004 at a strike price of $5.30, a
natural gas collared contract for 4,000 GJs per day for February and March 2004
that has a put option price of $5.23 and a call option price of $10.90 and a
natural gas collared contract for 6,000 GJs per day for April through October
2004 that has a put option price of $4.50 and a call option price of $6.50.

All of the outstanding contracts are based on the AECO-C
monthly price index. Settlement of the contracts at December 31, 2003 would have
resulted in a loss of $126,960. No payments have had to be made and no funds
have been received to date from the contracts.



---

UNAUDITED CONSOLIDATED INTERIM FINANCIAL STATEMENTS 
OF OLYMPIA ENERGY INC.
CONSOLIDATED BALANCE SHEETS
Olympia Energy Inc. 
(Unaudited) 
(in thousands of dollars)

|                                             | March 31, | December 31,     
|-------------------------------------------- | --------- | -----------------
|                                             | 2004      | 2003             
|                                             | $         | $                
|                                             |           | Restated - note 1
|ASSETS                                       |           |                  
|Current assets                               |           |                  
|Cash                                         | 2         | 2                
|Accounts
    receivable                      | 10,131    | 8,715            
|Investment in
    High Point Energy Corp.    | 10        | 10               
|Prepaid
    expenses                         | 574       | 486              
|                                             | 10,717    | 9,213            
|Property and equipment                       | 153,523   | 146,919          
|                                             | 164,240   | 156,132          
|LIABILITIES                                  |           |                  
|Current liabilities                          |           |                  
|Accounts
    payable and accrued liabilities | 17,453    | 18,004           
|Derivative
    financial instruments         | 538       | -                
|Bank debt                                    | 49,194    | 43,170           
|                                             | 67,185    | 61,174           
|Asset retirement obligations                 | 1,834     | 1,777            
|Future income taxes                          | 33,797    | 33,488           
|                                             | 102,816   | 96,439           
|                                             |           |                  
|SHAREHOLDERS' EQUITY                         |           |                  
|Capital stock                                | 21,658    | 22,574           
|Contributed surplus                          | 1,124     | 959              
|Retained earnings                            | 38,642    | 36,160           
|                                             | 61,424    | 59,693           
|                                             | 164,240   | 156,132          

Subsequent Event (note 5). 
See accompanying notes to unaudited consolidated financial statements.



---

CONSOLIDATED STATEMENTS OF EARNINGS AND RETAINED EARNINGS
Olympia Energy Inc.
 (Unaudited) 
(in thousands of dollars, except per share amounts)

|For the three months ended March 31,                  | 2004       | 2003                 
|----------------------------------------------------- | ---------- | ---------------------
|                                                      | $          | $                    
|                                                      |            | Restated - note
    1
|Revenue                                               |            |                      
|Petroleum and
    natural gas revenue                 | 15,953     | 14,402               
|Loss in value
    of derivative financial instruments | (538)      | -                    
|Royalties                                             | (3,257)    | (2,652)              
|Production
    expenses                               | (2,653)    | (1,935)              
|                                                      | 9,505      | 9,815                
|                                                      |            |                      
|Expenses                                              |            |                      
|General and
    administrative, net of recoveries     | 801        | 733                  
|Stock-based
    compensation cost                     | 164        | 157                  
|Interest on
    long-term debt                        | 496        | 372                  
|Depletion,
    depreciation and accretion             | 5,389      | 2,743                
|                                                      | 6,850      | 4,005                
|                                                      |            |                      
|Earnings before income taxes                          | 2,655      | 5,810                
|Current income taxes                                  | (795)      | (1,473)              
|Future income taxes                                   | 622        | (866)                
|Net earnings for the period                           | 2,482      | 3,471                
|Retained earnings - beginning of
    period           | 36,160     | 23,915               
|Retained earnings - end of
    period                 | 38,642     | 27,386               
|                                                      |            |                      
|Earnings per share                                    | 0.061      | 0.088                
|Earnings per share diluted                            | 0.061      | 0.086                
|Weighted average number of
    shares                 | 40,921,506 | 39,185,018           

See accompanying notes to unaudited consolidated financial statements.

D-14

---



CONSOLIDATED STATEMENTS OF CASH FLOWS

Olympia Energy Inc. 
(Unaudited) 
(in thousands of dollars)

|For the three months ended March 31,                  | 2004     | 2003                 
|----------------------------------------------------- | -------- | ---------------------
|                                                      | $        | $                    
|                                                      |          | Restated - note
    1
|Cash provided by (used in):                           |          |                      
|Operating activities                                  |          |                      
|Net earnings for the period                           | 2,482    | 3,461                
|Items not affecting cash:                             |          |                      
|Loss in value of derivative
    financial instruments | 538      | -                    
|Stock-based compensation cost                         | 164      | 174                  
|Future income taxes                                   | (622)    | 859                  
|Depletion, depreciation and
    accretion             | 5,389    | 2,743                
|Cash flow from operations                             | 7,951    | 7,237                
|Change in non-cash working
    capital                | 1,063    | (780)                
|                                                      | 9,014    | 6,457                
|                                                      |          |                      
|Investing activities                                  |          |                      
|Property and equipment additions                      | (11,936) | (4,932)              
|Proceeds on sale of properties                        | -        | 29                   
|Change in non-cash working
    capital                | (3,116)  | 1,261                
|                                                      | (15,052) | (3,642)              
|                                                      |          |                      
|Financing activities                                  |          |                      
|Issue of capital stock - net                          | 15       | 43                   
|Bank indebtedness                                     | 6,023    | (3,170)              
|                                                      | 6,038    | (3,127)              
|                                                      |          |                      
|Increase/(decrease) in cash                           | -        | (312)                
|Cash - beginning of period                            | 2        | 313                  
|Cash - end of period                                  | 2        | 1                    
|Interest paid                                         | 470      | 372                  

See accompanying notes to unaudited consolidated financial statements

D-15

---



NOTES TO THE CONSOLIDATED UNAUDITED FINANCIAL STATEMENTS

For the three months ended March 31, 2004 and 2003

The unaudited financial statements of the Company have been
prepared by management in accordance with generally accepted accounting
principles in Canada. They follow the same accounting policies and methods of
computation as the audited consolidated financial statements for the fiscal year
ended December 31, 2003 except as described in Note 1 below. The disclosures
included below are incremental to those included with the annual consolidated
financial statements. These unaudited financial statements should be read in
conjunction with those statements.

1. Changes in Accounting Policies

> (a)     Hedging Relationships
>   During the quarter the Company adopted Accounting Guideline
>   No. 13 as issued by the Canadian Institute of Chartered Accountants. This
>   guideline addresses the conditions necessary for a transaction to qualify for
>   hedge accounting, the formal documentation required to enable the use of hedge
>   accounting and the requirements to assess the effectiveness of hedging
>   relationships. Also, during the quarter, newly amended EIC 128 became
>   effective which requires financial instruments that are not designated as
>   hedges to be recorded at fair value on the balance sheet, with changes in fair
>   value recognized in earnings. The only derivative financial instruments used
>   by the Company currently and in the prior year are commodity price contracts.
>   The adoption of this guideline had the effect of reducing pre tax earnings for
>   the first quarter of 2004 by $538,000.
>   (b)     Full Cost Accounting
>   During the quarter, the Company also adopted the revised
>   guideline for Full Cost Accounting. The adoption of this guideline did not
>   have a material impact on the Company's financial position or results of
>   operations.
>   (c)     Stock-Based Compensation
>   During the quarter, the Company adopted the new accounting
>   policies for stock-based compensation that are embodied in revisions to
>   Section 3870 of the Accounting Handbook issued by the Canadian Institute of
>   Chartered Accountants.
>   The fair value of stock options granted after January 1, 2002 was estimated
>   at the date of grant using a Black-Scholes Option Pricing Model with the
>   following assumptions:
>   Three Months
>       Three Months
>       Year Ended
>       Year EndedEnded March 31,
>       Ended
>       December 31,
>       December 31,2004
>       March 31, 2003
>       2003
>       2002Volatility factor of expected marketprice
>       -
>       .64
>       .60
>       .65Weighted average risk-free interest rate(%)
>       -
>       3.55
>       3.79
>       4.17Dividend yield (%)
>       -
>       -
>       -
>       -Weighted average expected life of options(years)
>       -
>       3.0
>       3.0
>       4.0

D-16

---



> Retained earnings as at January 1, 2003 was restated to
>   reflect $281,000 of such compensation expensed in periods prior to that date.
>   Earnings and retained earnings as at December 31, 2003 were restated to
>   reflect $678,000 ($0.02 per share) of such compensation expensed during 2003.
>   Earnings for the first quarter of 2003 were restated to $3,471,000 to reflect
>   $157,000 ($0.004 per share) of such compensation expensed.
>   (d) Asset Retirement Obligations
>   During the quarter, the Company adopted the new accounting
>   policies for asset retirement obligations that are embodied in Section 3110 of
>   the Accounting Handbook issued by the Canadian Institute of Chartered
>   Accountants on a retroactive basis.
>   The consolidated financial statements for prior periods have been restated
>   to reflect the application of such asset retirement obligations.
>   Retained earnings as at January 1, 2003 was restated and
>   increased to $23,915,000 to reflect an adjustment of $476,000 relating to the
>   implementation of the requirements of Section 3110. In addition, property and
>   equipment was increased by $939,000, the future income tax liability was
>   increased by $252,000, the provision for site restoration of $1,135,000 was
>   eliminated and the asset retirement obligation was set up at $1,346,000.
>   Earnings and retained earnings as at December 31, 2003 were restated to
>   reflect a further adjustment of $11,000 increasing depletion and accretion on
>   asset retirement obligations during 2003. Earnings for the first quarter of
>   2003 were restated to reflect a reduction of depletion and accretion of
>   $(5,000) ($(0.00) per share) on asset retirement obligations during the first
>   quarter of 2003.

2. Share Capital

Issued and outstanding

|Common Shares                             | March 31, 2004  
|----------------------------------------- | ----------------
|                                          | Number of Shares
|Balance, January 1, 2004                  | 40,911,160      
|Issued upon exercise of stock
    options |                 
|Share issuance expenses                   |                 
|Tax effect of flow-through shares         | -               
|Balance, end of period                    | 39,398,094      
|Weighted average number of shares - basic | 40,921,506      
|- diluted                                 | 40,990,402      

Issuer Bids

On February 9, 2004 the Company announced that it would undertake a normal
course issuer bid allowing the purchase for cancellation of up to 3,000,000
common shares.

This bid terminates on February 10, 2005.

No shares were purchased in 2004.

D-17

---





|                                |           | Weighted Average
|------------------------------- | --------- | ----------------
|Stock Options                   | Shares    | Exercise Price  
|Outstanding beginning of period | 2,197,700 | 2.48            
|Granted                         | -         | -               
|Cancelled                       | (52,000)  | 2.80            
|Exercised                       | (15,500)  | 1.84            
|Outstanding end of period       | 2,130,200 | 2.47            

The following table summarizes information about stock options outstanding at
March 31, 2004:

|              |             | Weighted    |          |             |                 
|------------- | ----------- | ----------- | -------- | ----------- | ----------------
|              |             | Average     |          |             |                 
|              |             | Remaining   | Weighted | Number      | Weighted        
|              | Options     | Contractual | Average  | Exercisable | Average Exercise
|Grant Price   | Outstanding | Life        | Price    | (Vested)    | Price (Vested)  
|$1.01 - $2.00 | 694,200     | 1.504       | $1.7852  | 608,700     | $1.7733         
|$2.01 - $2.83 | 1,000,000   | 3.403       | $2.6473  | 95,000      | $2.3236         
|$2.84 - $3.17 | 436,000     | 2.811       | $3.17    | 179,200     | $3.17           
|Totals        | 2,130,200   | 2.663       | $2.4734  | 882,900     | $2.116          

That information has been determined as if the Company has
accounted for its employee stock options granted beginning January 1, 2002 using
the fair value method. The fair value for these options was estimated at the
date of grant using a Black-Scholes Option Pricing Model with the following
assumptions:

|                                                      | 2003 Grants | 2002 Grants
|----------------------------------------------------- | ----------- | -----------
|Volatility factor of expected market price            | .60         | .65        
|Weighted average risk-free
    interest rate (%)      | 3.35        | 3.97       
|Dividend yield (%)                                    | -           | -          
|Weighted average expected life of options
    (years) | 3.0         | 4.0        

The following table reconciles the common shares used in calculating net
earnings per common share:

|                                                         | Three months ended March 31,
|-------------------------------------------------------- | ----------------------------
|                                                         | 2004                        
|Weighted average common shares
    outstanding - basic   | 40,921,506                  
|Effect of dilutive stock options                         | 68,896                      
|Weighted average common shares
    outstanding - diluted | 40,990,402                  

3.

The nature of the Company's operations results in exposure to
fluctuating commodity prices. The Company may enter into certain contracts to
reduce its exposure to such risks from time to time to support planned capital
expenditures.

D-18

---



|                                                                        
|------------------------------------------------------------------------
|The following
    financial instruments were in place at March 31, 2004:
|                                                                        
|                                                                        
|Natural Gas                                                             
|Contracts                                                               
|AECO Collar                                                             

4.

There have been no material changes in the existence, likelihood or amount of
contingencies from the preceding annual financial statements.

5.

On April 6, 2004, the Company announced that it had reached
an agreement, subject to shareholder and regulatory approval, to enter into a
plan of arrangement with Provident Energy Trust. Under such arrangement,
Provident Energy Trust will acquire all of the shares of the Company at an
exchange rate of 0.345 Provident Energy Trust unit plus 0.1 share in a new
exploration company to be formed for each Company share tendered. Shareholders
are expected to approve the transaction at their annual and special general
meeting that will take place on May 27, 2004. Closing is expected to follow
shortly thereafter.



D-19

---

SCHEDULE E
AUDITED ANNUAL CONSOLIDATED FINANCIAL STATEMENTS 
OF VIRACOCHA ENERGY INC.
AUDITORS' REPORT
To the Directors of Viracocha Energy Inc.
We have audited the consolidated balance sheets of Viracocha
Energy Inc. as at December 31, 2003 and 2002 and the consolidated statements of
operations and retained earnings (deficit) and cash flows for the years then
ended. These consolidated financial statements are the responsibility of the
Company's management. Our responsibility is to express an opinion on these
consolidated 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 Company
as at December 31, 2003 and 2002 and the results of its operations and its cash
flows for the years then ended in accordance with Canadian generally accepted
accounting principles.
(signed) KPMG LLP
Chartered Accountants 
Calgary, Alberta
April 27, 2004





E-1

---

Viracocha Energy Inc. 
Consolidated Balance Sheets

|As at December 31,                                        | 2003        | 2002       
|--------------------------------------------------------- | ----------- | -----------
|                                                          | $           | $          
|                                                          |             |            
|Assets                                                    |             |            
|Current assets:                                           |             |            
|Accounts receivable                                       | 6,163,527   | 4,415,908  
|Prepaid expenses and
    other                            | 869,483     | 843,832    
|                                                          | 7,033,010   | 5,259,740  
|                                                          |             |            
|Oil and natural gas properties
    and equipment (note 5) | 119,912,678 | 40,614,567 
|                                                          |             |            
|Goodwill                                                  | 6,483,578   | -          
|                                                          | 133,429,266 | 45,874,307 
|                                                          |             |            
|Liabilities and Shareholders'
    Equity                  |             |            
|Current liabilities:                                      |             |            
|Accounts payable and accrued liabilities                  | 15,402,504  | 4,900,922  
|Capital
    tax payable                                   | 207,953     | 41,518     
|Revolving credit
    facility (note 6)                    | 42,504,822  | 2,019,362  
|                                                          | 58,115,279  | 6,961,802  
|Long-term debt (note 7)                                   | 2,968,189   | 3,436,233  
|                                                          |             |            
|Capital lease obligation (note
    8)                     | 93,688      | -          
|                                                          |             |            
|Deferred lease obligation (note
    13)                   | 131,124     | 297,039    
|                                                          |             |            
|Future income taxes (note 9)                              | 13,451,435  | 4,907,814  
|                                                          |             |            
|Provision for future site
    restoration costs           | 2,290,985   | 855,761    
|                                                          |             |            
|Shareholders' equity:                                     |             |            
|Share
    capital (note 10)                               | 52,242,797  | 32,579,258 
|Contributed surplus (note 10)                             | 181,850     | -          
|Retained earnings (deficit)                               | 3,953,919   | (3,163,600)
|                                                          | 56,378,566  | 29,415,658 
|                                                          | 133,429,266 | 45,874,307 

|                                                                    |                              
|------------------------------------------------------------------- | -----------------------------
|                                                                    |                              
|See accompanying
    notes to the consolidated financial statements
|                                                                    |                              
|Approved by the Board of
    Directors                              |                              
|                                                                    |                              
|Director, "signed" Rob Zakresky                                     | Director, "signed" Rob Jepson

E-2

---

Viracocha Energy Inc. 
Consolidated Statements of Operations and Retained Earnings (Deficit)

|Year ended December 31,                                             | 2003        | 2002       
|------------------------------------------------------------------- | ----------- | -----------
|                                                                    | $           | $          
|                                                                    |             |            
|Revenue:                                                            |             |            
|Oil and
    natural gas, net of royalties                           | 38,080,483  | 10,979,703 
|                                                                    |             |            
|Expenses:                                                           |             |            
|Production                                                          | 9,872,353   | 3,017,368  
|General
    and administrative (Note 2)                             | 2,089,791   | 1,985,194  
|Interest on indebtedness                                            | 1,432,119   | 345,912    
|Depletion, depreciation and amortization                            | 15,376,734  | 4,112,278  
|Amortization of
    convertible debenture                           | 106,956     | 394,390    
|                                                                    | 28,877,953  | 9,855,142  
|                                                                    |             |            
|Gain on equity investment                                           | -           | 135,306    
|Earnings before taxes                                               | 9,202,530   | 1,259,867  
|                                                                    |             |            
|Taxes (note 9):                                                     |             |            
|Capital
    taxes                                                   | 344,123     | 93,325     
|Future income taxes                                                 | 1,740,888   | 536,326    
|                                                                    | 2,085,011   | 629,651    
|                                                                    |             |            
|Net earnings                                                        | 7,117,519   | 630,216    
|Deficit, beginning of year                                          | (3,163,600) | (3,793,816)
|                                                                    |             |            
|Retained earnings (deficit), end of year                            | 3,953,919   | (3,163,600)
|                                                                    |             |            
|Net earnings per share:                                             |             |            
|Basic                                                               | 0.17        | 0.03       
|Diluted                                                             | 0.15        | 0.03       
|                                                                    |             |            
|See accompanying
    notes to the consolidated financial statements

E-3

---



|Viracocha Energy Inc.                                                    |              |             
|------------------------------------------------------------------------ | ------------ | ------------
|Consolidated
    Statements of Cash Flows                                |              |             
|                                                                         |              |             
|                                                                         |              |             
|Year ended December 31,                                                  | 2003         | 2002        
|                                                                         | $            | $           
|Cash provided by (used in):                                              |              |             
|                                                                         |              |             
|Operating:                                                               |              |             
|Net earnings                                                             | 7,117,519    | 630,216     
|Items not affecting cash:                                                |              |             
|Depletion, depreciation and amortization                                 | 15,376,734   | 4,112,278   
|Amortization of convertible debenture                                    | 106,956      | 394,390     
|Stock-based compensation                                                 | 181,850      | -           
|Gain on equity investment                                                | -            | (135,306)   
|Loss (gain) on sale of equipment                                         | (6,397)      | 12,491      
|Future income
    taxes                                                  | 1,740,888    | 536,326     
|Cash flow
    from operations                                            | 24,517,550   | 5,550,395   
|Net change in non-cash operating
    working capital                     | 1,136,685    | (226,400)   
|                                                                         | 25,654,235   | 5,323,995   
|                                                                         |              |             
|Financing:                                                               |              |             
|Increase in revolving credit facility                                    | 40,485,460   | 464,673     
|Decrease in deferred lease obligation                                    | (165,915)    | -           
|Decrease in capital lease obligation                                     | (20,177)     | -           
|Issuance of share capital                                                | 12,004,997   | 11,800,000  
|Share issue
    costs                                                    | (838,106)    | (988,293)   
|                                                                         | 51,466,259   | 11,276,380  
|                                                                         |              |             
|Investments:                                                             |              |             
|Corporate acquisition (Note 3)                                           | (15,076,376) | (11,784,335)
|Purchase and development of oil and natural gas properties and equipment | (72,152,099) | (5,998,755) 
|Sale of oil and natural gas properties and equipment                     | 1,936,730    | 889,000     
|Sale of investments                                                      | -            | 66,098      
|Site restoration costs incurred                                          | (48,704)     | (11,931)    
|Change in
    non-cash investing working capital                         | 8,219,955    | 239,548     
|                                                                         | (77,120,494) | (16,600,375)
|                                                                         |              |             
|Change in cash                                                           | -            | -           
|Cash, beginning of year                                                  | -            | -           
|                                                                         |              |             
|Cash, end of year                                                        | -            | -           
|                                                                         |              |             
|Interest paid                                                            | 1,432,119    | 341,984     
|Taxes paid                                                               | 192,109      | 110,016     
|                                                                         |              |             
|See accompanying notes
    to the consolidated financial statements      |              |             

E-4

---



|Viracocha Energy Inc.                             
|--------------------------------------------------
|Notes to the Consolidated Financial
    Statements
|Years ended December 31, 2003 and 2002            

Viracocha Energy Inc. (the "Company") is incorporated under
the Business Corporations Act (Alberta). The Company commenced trading on
the Toronto Stock Exchange on October 8, 2002. The Company is engaged in the
acquisition, development and exploration for and production and marketing, of
petroleum and natural gas reserves in Alberta and Saskatchewan.

1.    SIGNIFICANT ACCOUNTING POLICIES

> a)       Basis of
>   presentation
>   These consolidated financial statements include the
>   accounts of the Company and its wholly-owned subsidiary. These consolidated
>   financial statements have been prepared by management in accordance with
>   accounting principles generally accepted in Canada.
>   b)      Oil and natural gas properties and
>   equipment
>   The Company follows the full cost method of accounting
>   whereby all costs related to the acquisition of, exploring for and developing
>   oil and natural gas reserves are capitalized and charged against earnings as
>   set out below. Such costs include land acquisition costs, geological and
>   geophysical expenses, production equipment, carrying charges of non-producing
>   properties, costs of drilling both productive and nonproductive wells and
>   overhead charges directly related to acquisition, exploration and development
>   activities.
>   These costs, together with the estimated future costs to be
>   incurred in developing proved reserves, are depleted or depreciated using the
>   unit-of-production method based on the proved reserves before royalties as
>   estimated by independent petroleum engineers. Oil and natural gas reserves and
>   production are converted into equivalent units based upon estimated relative
>   energy content of six thousand cubic feet of natural gas to one barrel of oil.
>   The costs of undeveloped properties are excluded from the costs subject to
>   depletion and depreciation until it is determined whether proved reserves are
>   attributable to the properties or impairment occurs.
>   The capitalized costs less accumulated depletion and
>   depreciation and the provisions for future income taxes and site restoration
>   costs are limited to an amount equal to the estimated undiscounted future net
>   revenue from proved reserves, based on year-end prices plus the cost (net of
>   impairments) of unproved properties less estimated future capital costs,
>   future site restoration, general and administrative, financing and income tax
>   costs.
>   Proceeds from the sale of oil and natural gas properties are applied
>   against capitalized costs, with no gain or loss recognized, unless such a sale
>   would result in a change in the depletion rate of 20% or more.
>   c)      Other equipment
>   Other equipment is depreciated using the straight-line method over the
>   estimated useful life of three years.

E-5

---



|Viracocha Energy Inc.                             
|--------------------------------------------------
|Notes to the Consolidated Financial
    Statements
|Years ended December 31, 2003 and 2002            

> d)      Goodwill
>   Goodwill, which represents the excess of purchase price
>   over the fair value of net assets received in an acquisition, is tested for
>   impairment on an annual basis in the fourth quarter. A goodwill impairment
>   loss would be recognized when the carrying amount of goodwill exceeds its fair
>   value. Should the test result in an impairment, it will be charged to income
>   in the period of the impairment.
>   e)      Provision for future site restoration
>   costs

The estimated costs for future site restoration are
  provided for using the unit-of-production method. Estimated costs are based on
  engineering estimates in accordance with regulations in effect at year-end.
  The annual charge is included in depletion, depreciation and amortization
  expense and actual site restoration expenditures are charged to the
  accumulated provision account as incurred.

> f)       Use of estimates

The amounts recorded for depletion and depreciation of
  capital assets and the provision for future site restoration are based on
  estimates. The ceiling test is based on estimates of proved reserves,
  production rates, oil and gas prices, future costs and other relevant
  assumptions. By their nature, these estimates are subject to measurement
  uncertainty and the effect on the financial statements of changes in such
  estimates in future periods could be significant.

> g)      Joint venture accounting

Portions of the Company's oil and natural gas activities are conducted
  jointly with others and accordingly these financial statements reflect only
  the Company's proportionate interest in such activities.

> h)      Revenue recognition

Oil and natural gas revenues are recognized when title and risks pass to
  the purchaser.

> i)       Convertible debentures

Convertible debentures are recorded as the amount of
  proceeds received less the amount attributed to the conversion feature which
  is included as part of shareholders' equity. The difference between the
  recorded amount and the face value of the convertible debentures is charged to
  income and included in annual accretion of discount of convertible debentures
  on an effective yield basis.

> j)       Income taxes

The Company follows the liability method of accounting for
  future income taxes, whereby temporary differences arising from the difference
  between the tax basis of an asset or liability and its carrying amount on the
  balance sheet are used to calculate future income tax liabilities or assets.
  Future income tax liabilities or assets are calculated using tax rates
  anticipated to apply in the periods that the temporary differences are
  expected to reverse.

> k)      Stock-based compensation

The Company has a stock-based compensation plan, which is
  described in note 10(f). The Company applies the fair value method for valuing
  stock options granted to employees and directors. Under this method,
  compensation cost attributable to stock options granted to employees and
  directors is measured at

E-6

---



|Viracocha Energy Inc.                             
|--------------------------------------------------
|Notes to the Consolidated Financial
    Statements
|Years ended December 31, 2003 and 2002            

> fair value at the grant date and expensed over the vesting
>   period with a corresponding increase to contributed surplus. Upon the exercise
>   of the stock options, consideration paid together with the amount previously
>   recognized in contributed surplus is recorded as an increase to share capital.
>   l)      Flow-through shares
>   The resource expenditure deductions for income tax purposes
>   related to exploratory and development activities funded by flow-through share
>   arrangements are renounced to investors in accordance with income tax
>   legislation. Capital stock is reduced and future income tax liability is
>   increased by the estimated tax cost of these renounced expenditures.
>   m)     Hedging activities
>   The Company uses forward physical contracts to hedge
>   exposure to commodity prices. Gains and losses on oil and natural gas
>   transactions are reported as adjustments to oil and natural gas revenue when
>   the related production is delivered and sold.
>   n)     Per share information
>   Per share information is computed using the weighted
>   average number of common shares outstanding during the year. Diluted per share
>   information is calculated using the treasury stock method for options and
>   warrants and the "if-converted" method for convertible debentures. The
>   treasury stock method assumes that any proceeds obtained upon exercise of
>   options and warrants would be used to purchase common shares at the average
>   market price during the year. The "if-converted" method assumes that the
>   convertible debentures had been converted into common shares at the exercise
>   price. Any interest or amortization of the discount on the convertible
>   debenture is added back to net earnings (loss) for purposes of per share
>   calculations. No adjustment to diluted earnings per share is made if the
>   result of these calculations is anti-dilutive.

2.     CHANGE IN ACCOUNTING POLICY

> Effective January 1, 2003, the Company elected to
>   prospectively adopt new transitional provisions to the Canadian accounting
>   standards on stock-based compensation which requires the use of the fair value
>   method for valuing stock option grants. Under this method, compensation cost
>   attributable to stock options granted to employees and directors is measured
>   at fair value at the grant date and expensed over the vesting period with a
>   corresponding increase to contributed surplus. Upon the exercise of the stock
>   options, consideration paid together with the amount previously recognized in
>   contributed surplus is recorded as an increase to share capital. Pursuant to
>   the transition rules, the expense recognized applies to stock options granted
>   on or after January 1, 2003. As a result of adopting this amended standard,
>   net earnings for the year ended December 31, 2003 decreased by $181,850 and
>   contributed surplus increased by an equal amount. See Note 10 for additional
>   information regarding the nature of the plan and the associated compensation
>   expense. The Company has disclosed pro forma results for stock options granted
>   in 2002.

3.     CORPORATE ACQUISITIONS

> a)     On January 3, 2003, the Company
>   acquired all of the issued and outstanding shares of C&D Oil & Gas Ltd.
>   ("C&D"), a private company involved in the exploration, development and
>   production of oil and natural gas in Western Canada for a total purchase price
>   of $22,721,629. The acquired company's properties are located within the
>   Company's Central Alberta core area. The acquisition has been accounted for by
>   the purchase method of accounting as follows:

E-7

---



|Viracocha Energy Inc.                             
|--------------------------------------------------
|Notes to the Consolidated Financial
    Statements
|Years ended December 31, 2003 and 2002            



> Consideration of acquisition
>       Amount ($)Cash
>       15,000,000Issuance of 5,500,000 Class A
>       common shares
>       7,425,000Issuance of 500,000 share
>       purchase warrants
>       178,000Purchase price adjustment
>       64,023Transaction costs
>       54,60622,721,629Net assets acquired
>       Amount ($)Cash
>       42,253Working capital
>       502,179Capital assets
>       22,815,000Goodwill
>       6,483,578Future income taxes
>       (7,121,381)22,721,629The net cash consideration for the acquisition was
>   $15,076,376 comprised of the original $15,000,000 cash, purchase price
>   adjustments of $64,023 and transaction costs of $54,606 less a $42,253 cash
>   balance acquired from C&D.
>   b)     On July 16, 2002, the Company acquired all of the issued
>   and outstanding shares of Rozsa Petroleum Ltd. ("Rozsa"), a private company
>   involved in the exploration, development and production of oil and natural gas
>   in Western Canada for a total purchase price of $28,876,950. The acquisition
>   resulted in the Company establishing a strategic core area to further develop
>   and build upon. The acquisition has been accounted for by the purchase method
>   of accounting as follows:
>   Consideration of acquisition
>       Amount ($)Cash
>       15,138,000Issuance of 9,900,000 Class A
>       common shares (note 10(b))
>       13,365,000Adjustment under GAAP for
>       shares issued (note 10(b))
>       (3,465,000)Purchase price adjustment
>       88,950 Class A common shares (note 10(b))
>       120,083Adjustment under GAAP for
>       shares to be issued (note 10(b))
>       (31,133)Issuance of $3,000,000
>       convertible debenture (note 7)
>       3,000,000Issuance of 3,000,000 share purchase warrants
>       (note 10(b))
>       750,00028,876,950Net assets acquired
>       Amount ($)Cash
>       3,353,665Working capital
>       734,539Capital assets
>       28,658,166Future income
>       taxes
>       (2,900,760)Deferred rent
>       obligation (note 13)
>       (369,447)Future site restoration costs
>       (599,213)28,876,950

The Company acquired a cash balance of $3,353,665 with the
acquisition of Rozsa. The net cash consideration for the acquisition was
$11,784,335. Concurrent with the acquisition, the Company has reduced the
valuation allowance recorded against the realization of future income taxes in
the amount of $1,171,801. This has been reflected in the net assets acquired as
a reduction in the recorded amounts for capital assets and future income taxes.

E-8

---



|Viracocha Energy Inc.                             
|--------------------------------------------------
|Notes to the Consolidated Financial
    Statements
|Years ended December 31, 2003 and 2002            

4.     INVESTMENTS

During the year ended December 31, 2002, the Company sold its
31% interest in Innovative Production Technologies Ltd. ("IPTL"). The total
consideration of $926,098 was comprised of cash of $66,098 and 600,000 common
shares of the Company. Of the total investment sold, 64% was sold to a former
officer of the Company, 24% was sold to a consultant to the Company and the
remaining 12% was sold to arm's length parties.

5.    OIL AND NATURAL GAS PROPERTIES AND EQUIPMENT

|                               |             | Accumulated   |               
|------------------------------ | ----------- | ------------- | --------------
|                               |             | Depletion and |               
|                               | Cost        | Depreciation  | Net Book Value
|2003                           | $           | $             | $             
|Oil and natural gas properties | 141,062,516 | 21,799,958    | 119,262,558   
|Other equipment                | 911,490     | 261,370       | 650,120       
|                               | 141,974,006 | 22,061,328    | 119,912,678   



|                               |            | Accumulated   |               
|------------------------------ | ---------- | ------------- | --------------
|                               |            | Depletion and |               
|                               | Cost       | Depreciation  | Net Book Value
|2002                           | $          | $             | $             
|Oil and natural gas properties | 48,133,282 | 8,040,943     | 40,092,339    
|Other equipment                | 634,078    | 111,850       | 522,228       
|                               | 48,767,360 | 8,152,793     | 40,614,567    

As at December 31, 2003, the cost of oil and natural gas
properties includes $11,433,611 (2002 - $7,191,732) relating to properties from
which there is no production and which have been excluded from costs subject to
depletion and depreciation. During the year ended December 31, 2003 the
provision for depletion, depreciation and amortization includes $1,483,928 (2002
- $220,861) for future site restoration. During the year ended December 31,
2003, the Company capitalized $731,335 (2002 - $54,892) of general and
administrative costs.

As at December 31, 2003, the estimated future site restoration costs are
$12,268,000 (2002 - $4,336,500).

6.    REVOLVING CREDIT FACILITY

The Company has a revolving operating demand loan credit
facility available up to $46.0 million bearing interest at prime plus a premium
ranging between 0% and 1.25% based on the Company's debt to cash flow ratio with
a Canadian bank. The credit facility also includes a $4.0 million non-revolving
development demand loan bearing interest at prime plus 0.75%. The credit
facility is secured by a $75 million fixed and floating charge debenture on the
assets of the Company.

7.    LONG-TERM DEBT

The convertible debentures with a principal sum aggregating
$575,000 bear interest at the rate of 8.0% per annum, calculated monthly, are
repayable in full on November 9, 2004, and are unsecured. After eighteen months
from the issue date the debentures are callable, under certain conditions at the
option of the Company, together with interest accrued on such principal. In
addition, the debentures are convertible, at the option of the

E-9

---



|Viracocha Energy Inc.                             
|--------------------------------------------------
|Notes to the Consolidated Financial
    Statements
|Years ended December 31, 2003 and 2002            

holder, at a conversion price of $1.48 per share at anytime prior to the
close of business on November 9, 2004. In conjunction with the convertible
debentures, 287,500 warrants were issued (note 10(d)).

During the year ended December 31, 2003 the Company issued
388,511 common shares at a price of $1.48 per share to certain officers and a
director of the Company upon the conversion of the $575,000 principal value
convertible debentures.

The convertible debentures with a principal sum aggregating
$3,000,000 bear interest at the rate of 7.5% per annum, calculated quarterly,
are repayable in full on July 15, 2005, and are unsecured. The debentures are
callable, under certain conditions at any time subsequent to July 16, 2004, at
the option of the Company, together with interest accrued on such principal. In
addition, the debentures are convertible, at the option of the holder, at a
conversion price of $1.10 per share at anytime prior to the close of business on
July 15, 2005.

The principal amount has been allocated between debt and equity components as
follows:

|                                                 | 2003      | 2002     
|------------------------------------------------ | --------- | ---------
|                                                 | $         | $        
|8.0% Convertible debenture                       | -         | 575,000  
|7.5% Convertible debenture                       | 3,000,000 | 3,000,000
|Less equity component                            | (533,157) | (533,157)
|Add: accretion of discount on conversion feature | 501,346   | 394,390  
|                                                 | 2,968,189 | 3,436,233

8.     CAPITAL LEASE OBLIGATION

Leases related to automobiles, having an initial cost of
$154,151 have been classified as capital leases and are included in capital
assets. The capital lease obligations reflect the present value of future
minimum payments under these leases, discounted at the interest rates implicit
in the leases. The interest rates implicit in these leases range from 7.7% to
8.3% with a weighted average rate of 8.0%. At December 31, 2003, the future
minimum lease payments under capital leases were:

|                                                                               | 2003   
|------------------------------------------------------------------------------ | -------
|                                                                               | $      
|2004                                                                           | 49,509 
|2005                                                                           | 47,636 
|2006                                                                           | 45,925 
|2007                                                                           | 8,750  
|Total minimum lease payments                                                   | 151,820
|Less: Amount representing interest                                             | 17,846 
|Present value of minimum lease payments                                        | 133,974
|Less: Current portion included in accounts
    payable and accrued liabilities | 40,286 
|                                                                               | 93,688 

9.     TAXES

> a)     The provision for income taxes
>   on the statement of operations and retained earnings (deficit) differs from
>   the amount that would be computed by applying the expected tax rates to net
>   earnings before income taxes. The reasons for the difference between such
>   expected income tax expense and the amount recorded are as follows:

E-10

---



|Viracocha Energy Inc.                             
|--------------------------------------------------
|Notes to the Consolidated Financial
    Statements
|Years ended December 31, 2003 and 2002            

> 2003
>       2002Income tax rate
>       40.62%
>       42.12%$
>       $Expected income tax expense
>       (recovery)
>       3,738,068
>       530,656Increase (decrease) in income
>       taxes resulting from:Non-deductible
>       crown charges
>       2,528,173
>       932,278Alberta Royalty
>       Tax Credit
>       (187,880)
>       (102,632)Resource
>       allowance
>       (2,538,637)
>       (768,515)Attributed
>       Canadian Royalty Income
>       -
>       (70,468)Capital taxes
>       344,123
>       93,325Reduction of tax
>       rates
>       (1,953,507)
>       76,821Other
>       154,671
>       (61,814)2,085,011
>       629,651b) The components
>       of the net future income tax liability at December 31 are as follows:2003
>       2002$
>       $Future income tax liabilities:Capital assets
>       15,060,460
>       5,914,295Future income tax assets:Future site
>       restoration costs
>       (793,139)
>       (270,335)Share issue costs
>       (538,078)
>       (444,916)Deferred rent
>       obligation
>       (47,768)
>       (125,113)Capital lease
>       obligation
>       (47,400)
>       -Long-term debt
>       (182,640)
>       (166,117)Net future income tax
>       liability
>       13,451,435
>       4,907,814

10. SHARE CAPITAL

> a)     Authorized

Unlimited number of Class A Common Shares 
    Unlimited number of Class B Common Shares 
    Unlimited number of Preferred Shares

E-11

---



|Viracocha Energy Inc.                             
|--------------------------------------------------
|Notes to the Consolidated Financial
    Statements
|Years ended December 31, 2003 and 2002            

|
|

> b)      Issued
>       and outstanding Class A Common SharesDecember 31, 2003
>       December 31, 2002Number of
>       Amount
>       Number of
>       Amountshares
>       $
>       shares
>       $Balance, beginning of year
>       34,078,869
>       31,296,101
>       15,139,919
>       12,826,172Exercise of Special Warrants
>       -
>       -
>       7,000,000
>       7,000,000Shares issued for cash
>       5,581,394
>       11,999,997
>       300,000
>       300,000Corporate acquisition
>       5,500,000
>       7,425,000
>       9,900,000
>       13,365,000Adjustment under GAAP for corporate acquisition(see following)
>       -
>       -
>       -
>       (3,465,000)Purchase price adjustment
>       -
>       -
>       88,950
>       120,083Adjustment under GAAP for corporate acquisition(see following)
>       -
>       -
>       -
>       (31,133)Flow-through shares issued for cash
>       -
>       -
>       2,250,000
>       4,500,000Future tax effect on flow-through shares
>       -
>       -
>       -
>       (1,900,000)Shares cancelled and returned to treasury upon saleof investment (note 4)
>       -
>       -
>       (600,000)
>       (860,000)Exercise of stock options
>       5,000
>       5,000
>       -
>       -Conversion of debentures
>       388,511
>       575,000
>       -
>       -Share
>       issue costs
>       -
>       (838,106)
>       -
>       (988,293)Future tax effect on share issue costs
>       -
>       318,648
>       -
>       429,272Balance, end of year
>       45,553,774
>       50,781,640
>       34,078,869
>       31,296,101Share
>       purchase warrants for corporate acquisition
>       -
>       928,000
>       -
>       750,000Equity portion of convertible debenture
>       -
>       533,157
>       -
>       533,15745,553,774
>       52,242,797
>       34,078,869
>       32,579,258No Class B common shares or preferred shares have been issued.
>   As partial consideration for the acquisition of Rozsa on
>   July 16, 2002, the Company issued 9,900,000 common shares at a negotiated
>   value of $1.35 per common share. An additional 88,950 common shares were
>   issued at the negotiated price of $1.35 per common share as consideration for
>   post closing purchase price adjustments. In determining fair value in a
>   business combination (i.e. the acquisition of Rozsa), generally accepted
>   accounting principles look to both the fair value given and the fair value
>   received in recording the transaction. As the Company was a private company at
>   the time of the acquisition, it was necessary, for accounting purposes, to
>   record the share value based on recent issuances of common shares for cash
>   consideration as opposed to the negotiated price noted above. As such, the
>   share capital was reduced to reflect the difference between the negotiated
>   price and other share issuances for cash completed in July 2002.
>   c)     Special Warrants
>   On July 10, 2002 the Company closed a Special Warrant
>   financing whereby the Company issued 7,000,000 Special Warrants for $1.00 per
>   Special Warrant for proceeds of $6,621,955, net of share issue costs and
>   related future income tax. The Special Warrants were then converted to Class A
>   common shares upon receipt of final prospectus on September 23, 2002.

E-12

---



|Viracocha Energy Inc.                             
|--------------------------------------------------
|Notes to the Consolidated Financial
    Statements
|Years ended December 31, 2003 and 2002            

> d)     Warrants
>   Weighted averageexercise priceNumber of warrants
>       $Balance at December 31, 2002
>       3,587,500
>       1.04Corporate acquisition
>       500,000
>       1.35Balance at December 31, 2003
>       4,087,500
>       1.08In conjunction with the $575,000 principle sum convertible
>   debentures (note 7), 287,500 warrants were issued. Each warrant entitles the
>   holder to acquire one Class A common share of the Company at an exercise price
>   of $1.48 per share. If not exercised, these warrants will expire November 9,
>   2004.
>   The 3,000,000 warrants issued in connection with the
>   corporate acquisition of Rozsa are exercisable into one Class A common share
>   of the Company at any time commencing at issuance and ending July 16, 2004 at
>   an exercise price of $1.00 per share.
>   On July 18, 2002 the Company issued 300,000 warrants to an
>   officer of the Company in conjunction with a private placement of its Class A
>   common shares. Each warrant is exercisable into one Class A common share of
>   the Company at any time commencing at issuance and ending July 15, 2005 at a
>   exercise price of $1.00 per share.
>   The 500,000 warrants issued in connection with the
>   corporate acquisition of C&D are exercisable into one Class A common share of
>   the Company at any time commencing at issuance and ending December 31, 2004 at
>   an exercise price of $1.35 per share.
>   e)     Issue of flow-through shares
>   During the year ended December 31, 2002, the Company issued
>   2,250,000 common shares on a flow-through basis for cash consideration of
>   $4,500,000. Of these shares, 120,000 were issued to directors and officers of
>   the Company.
>   f)     Stock options
>   Subject to shareholder approval, the Company has authorized
>   the issuance of 4,550,000 common shares under a stock option plan enabling
>   certain officers, directors, employees and consultants to purchase common
>   shares. The Company has reserved for issuance 4,434,300 common shares for this
>   purpose. Under the plan, the exercise price of each option equals the market
>   price of the Company's shares on the date of the grant. The options vest over
>   a period of 3 years and an option's maximum term is 5 years. As at December
>   31, 2003, 4,434,300 (2002 - 2,898,000) options have been granted and are
>   outstanding at prices ranging from $0.40 -$2.65 per share with expiry dates
>   ranging from May 31, 2005 to December 3, 2008.
>   Stock option transactions and the number of share options outstanding are
>   summarized as follows:

E-13

---



|Viracocha Energy Inc.                             
|--------------------------------------------------
|Notes to the Consolidated Financial
    Statements
|Years ended December 31, 2003 and 2002            

> Weighted averageNumber of
>       exercise priceoptions
>       $Balance, December 31, 2001
>       740,000
>       0.79Options granted
>       2,258,000
>       1.28Options cancelled
>       (100,000)
>       1.25Balance, December 31, 2002
>       2,898,000
>       1.15Options granted
>       1,541,300
>       2.40Options exercised
>       (5,000)
>       1.00Balance, December 31, 2003
>       4,434,300
>       1.59Exercisable at December 31, 2002
>       445,000
>       0.79Exercisable at December 31, 2003
>       1,467,700
>       1.10The range of exercise prices of the Company's stock options outstanding at
>   December 31, 2003 is as follows:
>   Option Pricing
>       Outstanding Options
>       Exercisable OptionsWeighted
>       Weighted
>       
>       WeightedAverage
>       Average
>       
>       AverageRange of
>       Number
>       Exercise
>       Years to
>       Number
>       Exerciseexercise prices
>       outstanding
>       Price $
>       Expiry
>       exercisable
>       Price $$0.00 - $0.99
>       355,000
>       0.40
>       1.7
>       323,300
>       0.40$1.00 - $1.99
>       2,658,000
>       1.28
>       3.6
>       1,042,700
>       1.21$2.00 - $2.65
>       1,421,300
>       2.46
>       4.7
>       101,700
>       2.25$0.00 - $2.65
>       4,434,300
>       1.59
>       3.8
>       1,467,700
>       1.10g)     Escrow

At December 31, 2003, there were 2,440,234 common shares
  held in escrow pursuant to the Escrow Agreement and Toronto Stock Exchange
  listing requirements. Subsequent to December 31, 2003, all of the remaining
  shares were released from escrow.

> h)     Stock-based compensation

Effective January 1, 2003, the Company adopted the new
  transitional provisions to the Canadian accounting standards on stock-based
  compensation, which requires the use of the fair value method for valuing
  stock options granted to employees and directors. Pursuant to the transition
  rules, the expense recognized applies to stock options granted in 2003. If the
  fair value method had been used for options granted in 2002, the Company's net
  earnings and net earnings per share for the years ended December 31, 2003 and
  2002 would approximate the following pro forma amounts:

|                                      | 2003      | 2002   
|------------------------------------- | --------- | -------
|                                      | $         | $      
|Compensation costs                    | 562,338   | 156,118
|Net earnings:                         |           |        
|As
      reported                     | 7,117,519 | 630,216
|Pro forma                             | 6,555,181 | 474,098
|Basic net earnings per share:         |           |        
|As
      reported                     | 0.17      | 0.03   
|Pro
      forma                       | 0.15      | 0.02   
|Diluted net earnings per
      share: |           |        
|As
      reported                     | 0.15      | 0.03   
|Pro
      forma                       | 0.14      | 0.02   

E-14

---



|Viracocha Energy Inc.                             
|--------------------------------------------------
|Notes to the Consolidated Financial
    Statements
|Years ended December 31, 2003 and 2002            

> The fair value of each option granted is estimated on the date of grant
>   using the Black - Scholes option pricing model with the following weighted
>   average assumptions:
>   2003
>       2002Fair value per option
>       $1.08
>       $0.50Risk-free interest rate
>       4.0%
>       4.2%Expected life
>       4 years
>       4 yearsExpected volatility
>       52%
>       43%Dividend yield
>       -
>       -i)     Per share information
>   The weighted average number of shares outstanding and net earnings for the
>   determination of basic and diluted per share amounts are as follows:

|                                                                  | 2003       | 2002      
|----------------------------------------------------------------- | ---------- | ----------
|Numerator:                                                        |            |           
|Net earnings                                                      | $7,117,519 | $630,216  
|Adjustment for
      interest expense and amortization related to |            |           
|convertible debentures, net of income tax effect                  | 231,499    | -         
|Net earnings, adjusted                                            | $7,349,018 | $630,216  
|                                                                  |            |           
|Denominator:                                                      |            |           
|Weighted-average
      shares used to calculate basic EPS         | 42,749,281 | 23,271,789
|Dilutive effect
      of options, warrants, and convertible       |            |           
|debentures                                                        | 6,653,684  | 998,803   
|Diluted number of shares                                          | 49,402,965 | 24,270,592

11.     RELATED PARTY TRANSACTIONS

> a)     During the year ended December 31, 2002, the
>   Company purchased assets and services of approximately $242,000 from IPTL.
>   These transactions were undertaken at the exchange amount.
>   b)     During the year ended December
>   31, 2002, the Company purchased assets of $56,000 from an oilfield supply
>   company which is 50% owned by a director of the Company. These transactions
>   were undertaken at the exchange amount.
>   c)     During the year ended December
>   31, 2003 the Company issued 388,511 common shares at a price of $1.48 per
>   share to certain officers and a director of the Company upon the conversion of
>   the $575,000 principal value convertible debentures.
>   d)     During the year ended December 31, 2002, a
>   convertible debenture amounting to $1,000,000 was issued to a director of the
>   Company.

E-15

---



|Viracocha Energy Inc.                             
|--------------------------------------------------
|Notes to the Consolidated Financial
    Statements
|Years ended December 31, 2003 and 2002            

12.     FINANCIAL INSTRUMENTS

> a)     Fair values
>   The carrying value of accounts receivable, revolving credit facility,
>   capital taxes payable, long-term debt and accounts payable and accrued
>   liabilities approximate their fair value.
>   b)     Interest rate risk
>   As at December 31, 2003 the Company was exposed to floating interest rates
>   with respect to its revolving credit facility.
>   c)     Credit risk
>   A substantial portion of the Company's accounts receivable
>   are with customers and joint venture partners in the oil and gas industry and
>   are subject to normal industry credit risks. The credit risk on receivables is
>   mitigated by selling to a number of purchasers as well as review of customer
>   credit worthiness.
>   d)     Hedging activities
>   The Company uses forward physical contracts to hedge
>   exposure to commodity prices. Gains and losses on oil and natural gas
>   transactions are reported as adjustments to oil and natural gas revenue when
>   the related production is delivered and sold. The estimated fair market value
>   at December 31, 2003, had the contracts been settled at that time, would have
>   been a loss of $1.3 million.
>   At December 31, 2003, the Company held certain physical
>   hedges for a portion of its oil production. Light oil contracts are referenced
>   to the West Texas Intermediate ("WTI") price. The terms of the physical
>   contracts are as follows:

|                            | Volume | WTI    
|--------------------------- | ------ | -------
|Term                        | Bbls/d | $US/bbl
|Jan 1, 2004 to Dec 31, 2004 | 500    | 26.00  
|an 1, 2004 to Mar 31, 2004  | 800    | 29.85  

Subsequent to year-end the Company entered into physical hedge contracts as
  follows:

|                                  | Volume | WTI    
|--------------------------------- | ------ | -------
|Term                              | Bbls/d | $US/bbl
|Mar 1, 2004 to Mar 31, 2004       | 500    | 34.54  
|Apr 1, 2004 to
      Jun 30, 2004 | 500    | 31.25  
|Apr 1, 2004 to
      Jun 30, 2004 | 500    | 32.15  
|Jul 1, 2004 to Sep 30, 2004       | 700    | 31.03  

The Company is exposed to foreign currency fluctuations as crude prices
  received for a portion of its contracts entered into subsequent to year-end
  are referenced to U.S. dollar denominated prices.

Other than as outlined above, the Company's oil and natural
  gas production is marketed and sold on the spot market to area aggregators
  based on daily spot prices that are adjusted for product quality and
  transportation costs.

E-16

---



|Viracocha Energy Inc.                             
|--------------------------------------------------
|Notes to the Consolidated Financial
    Statements
|Years ended December 31, 2003 and 2002            

> The Company fixed the price of electricity on 2.5 megawatts
>   per hour ("Mw/h") from January 1, 2004 through December 31, 2005 at a price of
>   $45.875/Mw/h. The estimated market value at December 31, 2003, had the
>   contract been settled at that time, would have been a gain of $291,600.

13.     COMMITMENTS

> The Company is committed to payments under various operating
>   leases for office space as follows:
>   $2004
>       407,2622005
>       404,5532006
>       356,9072007
>       253,5121,422,234The Company has entered into a sublease agreement
>   commencing September 1, 2002 whereby it is able to recover a portion of the
>   lease commitments over the remaining life of the lease. The above amounts are
>   tabled as net after sublease. The above amounts include the $131,124 (2002 -
>   $297,039) deferred lease obligation relating to commitments on Rozsa office
>   space no longer utilized.

14.     SUBSEQUENT EVENT

> On April 6, 2004, Provident Energy Trust (the "Trust"), and
>   the Company entered into an arrangement agreement pursuant to which the Trust
>   agreed to acquire the Company other than certain producing properties and
>   undeveloped acreage in Alberta ("Retained Assets") that are to be distributed
>   to a newly formed corporation, Chamaelo Energy Inc. ("Chamaelo"). Under the
>   terms of the agreement, the Trust will acquire all of the issued and
>   outstanding common shares of the Company in exchange for 0.248 of a Provident
>   unit representing market value of approximately $153.9 million and 0.10 of a
>   Chamaelo share with a carrying value of $13.6 million. Pursuant to the
>   agreement the trust will assume net debt of approximately $40.6 million for a
>   total aggregate value of approximately $208.1 million.
>   Completion of the proposed transactions under the agreement
>   will result in the issuance of 5.6 million Chamaelo common shares as
>   consideration for the transfer of the Retained Assets. Pursuant to the
>   agreement, 56.8 million fully diluted common shares of Viracocha, including
>   the conversion of all stock options, warrants, and convertible debentures into
>   common shares, will be exchanged for Chamaelo common shares on a one for ten
>   basis. As Chamaelo and Viracocha are deemed to be related parties, the net
>   assets acquired by Chamaelo will be recorded at Viracocha's net book value of
>   approximately $13.6 million. The agreement is subject to shareholder approval
>   on or about May 27, 2004.

E-17

---

UNAUDITED CONSOLIDATED INTERIM FINANCIAL STATEMENTS 
OF VIRACOCHA ENERGY INC.
Viracocha Energy Inc. 
Consolidated Balance Sheets

|                                                                    | As at       | As at           
|------------------------------------------------------------------- | ----------- | ----------------
|                                                                    | March 31    | December 31     
|                                                                    | 2004        | 2003            
|                                                                    | (unaudited) | (audited)       
|                                                                    |             | (restated note2)
|                                                                    | $           | $               
|Assets                                                              |             |                 
|Current assets:                                                     |             |                 
|Accounts receivable                                                 | 6,151,938   | 6,163,527       
|Prepaid expenses and other                                          | 555,781     | 869,483         
|                                                                    | 6,707,719   | 7,033,010       
|Oil and natural gas properties
    (note 3)                         | 131,007,966 | 126,289,451     
|                                                                    |             |                 
|Goodwill                                                            | 6,483,578   | 6,483,578       
|                                                                    | 144,199,263 | 139,806,039     
|Liabilities and Shareholders' Equity                                |             |                 
|Current liabilities:                                                |             |                 
|Accounts payable and accrued liabilities                            | 9,880,311   | 15,402,504      
|Capital
    tax payable                                             | 138,115     | 207,953         
|Revolving credit
    facility (note 4)                              | 49,786,087  | 42,504,822      
|                                                                    | 59,804,513  | 58,115,279      
|                                                                    |             |                 
|Long-term debt                                                      | 2,976,208   | 2,968,189       
|                                                                    |             |                 
|Capital lease obligation                                            | 83,674      | 93,688          
|                                                                    |             |                 
|Deferred lease obligation                                           | 111,675     | 131,124         
|                                                                    |             |                 
|Future income taxes                                                 | 14,336,083  | 13,837,951      
|                                                                    |             |                 
|Asset retirement obligation
    (note 2)                            | 7,763,383   | 7,551,306       
|                                                                    |             |                 
|Shareholders' equity:                                               |             |                 
|Share
    capital (note 6)                                          | 52,250,597  | 52,242,797      
|Contributed surplus                                                 | 423,667     | 181,850         
|Retained earnings                                                   | 6,449,463   | 4,683,855       
|                                                                    | 59,123,727  | 57,108,502      
|Subsequent event (note 10)                                          |             |                 
|                                                                    | 144,199,263 | 139,806,039     
|See accompanying notes to the consolidated
    financial statements |             |                 

E-18

---

Viracocha Energy Inc. 
Consolidated Statements of Operations and Retained Earnings (Deficit)(unaudited)

|                                                                          | Three
    months ended
|------------------------------------------------------------------------- | ----------------------
|                                                                          | March 31              
|                                                                          | 2004                  
|                                                                          |                       
|                                                                          | $                     
|                                                                          |                       
|Revenue:                                                                  |                       
|Oil and
    natural gas, net of royalties                                 | 12,898,525            
|                                                                          |                       
|Expenses:                                                                 |                       
|Production                                                                | 3,461,402             
|General
    and administrative                                            | 688,860               
|Interest                                                                  | 624,803               
|Depletion, depreciation and accretion                                     | 5,778,168             
|Amortization of
    convertible debenture                                 | 8,019                 
|                                                                          | 10,561,252            
|                                                                          |                       
|Earnings before taxes                                                     | 2,337,273             
|                                                                          |                       
|Taxes:                                                                    |                       
|Capital
    taxes                                                         | 73,533                
|Future income taxes                                                       | 498,132               
|                                                                          | 571,665               
|                                                                          |                       
|Net earnings                                                              | 1,765,608             
|                                                                          |                       
|Retained earnings (deficit),
    beginning of period as previously stated |                       
|                                                                          | 3,953,919             
|Change in accounting policy (note 2)                                      | 729,936               
|Retained earnings (deficit), beginning of period
    as restated          | 4,683,855             
|                                                                          |                       
|Retained earnings (deficit), end of period                                | 6,449,463             
|                                                                          |                       
|Net earnings per share:                                                   |                       
|Basic                                                                     | 0.04                  
|Diluted                                                                   | 0.03                  
|                                                                          |                       
|See accompanying notes to the
    consolidated financial statements       |                       

E-19

---



|                                                                    |                        |                  
|------------------------------------------------------------------- | ---------------------- | -----------------
|Viracocha Energy Inc.                                               |                        |                  
|Consolidated Statements of Cash
    Flows                           |                        |                  
|(unaudited)                                                         |                        |                  
|                                                                    | Three
    months ended
|                                                                    | March
    31          
|                                                                    | 2004                   | 2003             
|                                                                    |                        | (restated note 2)
|                                                                    | $                      | $                
|Cash provided by (used in):                                         |                        |                  
|                                                                    |                        |                  
|Operating:                                                          |                        |                  
|Net earnings                                                        | 1,765,608              | 2,368,443        
|Items not affecting cash:                                           |                        |                  
|Depletion, depreciation and accretion                               | 5,778,168              | 3,048,343        
|Amortization of convertible debenture                               | 8,019                  | 26,373           
|Stock-based compensation                                            | 241,817                | 27,078           
|Future income taxes                                                 | 498,132                | 1,526,488        
|Cash
    flow from operations                                       | 8,291,744              | 6,996,725        
|Net change in non-cash operating working capital                    | (1,342,992)            | (155,599)        
|                                                                    | 6,948,752              | 6,841,126        
|                                                                    |                        |                  
|Financing:                                                          |                        |                  
|Increase in revolving credit facility                               | 7,281,265              | 13,815,951       
|Decrease in deferred lease obligation                               | (19,449)               | (71,586)         
|Decrease in capital lease obligation                                | (10,014)               | -                
|Issuance of share capital                                           | 7,800                  | -                
|Share issue costs                                                   | -                      | (34,755)         
|                                                                    | 7,259,602              | 13,709,610       
|                                                                    |                        |                  
|Investments:                                                        |                        |                  
|Corporate acquisition                                               | -                      | (15,076,376)     
|Purchase and development of oil and natural gas properties          | (10,284,606)           | (9,129,489)      
|Sale of oil and natural gas properties                              | -                      | 2,000,000        
|Change in
    non-cash investing working capital                    | (3,923,748)            | 1,655,129        
|                                                                    | (14,208,354)           | (20,550,736)     
|                                                                    |                        |                  
|Change in cash                                                      | -                      | -                
|Cash, beginning of period                                           | -                      | -                
|                                                                    |                        |                  
|Cash, end of period                                                 | -                      | -                
|                                                                    |                        |                  
|See accompanying notes to the
    consolidated financial statements |                        |                  

E-20

---



|Viracocha Energy Inc.                             
|--------------------------------------------------
|Notes to the Consolidated Financial
    Statements
|Three months ended December 31, 2004 and 2003     

Viracocha Energy Inc. (the "Company") is incorporated under
the Business Corporations Act(Alberta). The Company commenced trading on
the Toronto Stock Exchange on October 8, 2002. The Company is engaged in the
acquisition, development and exploration for and production and marketing, of
petroleum and natural gas reserves in Alberta and Saskatchewan.

1.

The interim consolidated financial statements of Viracocha
Energy Inc. ("Viracocha" or "the Company") have been prepared by management in
accordance with accounting principles generally accepted in Canada. The interim
financial statements have been prepared following the same accounting policies
and methods of computation as the financial statements for the fiscal year ended
December 31, 2003 except as noted below. The disclosures provided below are
incremental to those included with the annual financial statements. The interim
financial statements should be read in conjunction with the financial statements
and the notes thereto in the Company's consolidated financial statements for the
year ended December 31, 2003.

2.

Asset Retirement Obligations - Effective January 1, 2004,
the Company adopted the new Canadian accounting standard on asset retirement
obligations ("ARO"). The new standard requires the Company to recognize the
liability associated with future site reclamation costs in the financial
statements at the time when the liability is incurred. ARO obligations are
initially measured at fair value and subsequently adjusted for the accretion of
discount and any changes to the underlying cash flows. The asset retirement cost
is capitalized to oil and natural gas properties and equipment and amortized
into earnings on a basis consistent with depletion and depreciation. This change
in accounting policy has been applied retroactively with restatement of prior
periods presented for comparative purposes. The effect of the adoption is
presented below as increases (decreases):

|Balance sheet                                                              | December 31, 2003  | December 31, 2002
|-------------------------------------------------------------------------- | ------------------ | -----------------
|                                                                           | $                  | $                
|Asset retirement costs, included
    in oil and natural gas properties and |                    |                  
|equipment                                                                  | 6,376,773          | 2,352,634        
|Asset retirement obligations                                               | 7,551,306          | 2,679,589        
|Accumulated provision for future
    site restoration costs                | (2,290,985)        | (855,761)        
|Future income taxes                                                        | 386,516            | 167,050          
|Retained earnings                                                          | 729,936            | 361,756          
|                                                                           |                    |                  
|                                                                           | Three months ended | Year ended       
|Statement of operations                                                    | March 31, 2003     | December 31, 2003
|                                                                           | $                  | $                
|Accretion expense                                                          | 46,938             | 187,752          
|Depletion and depreciation on
    asset retirement costs                   | 127,059            | 708,530          
|Amortization of estimated future
    site restoration costs                | (393,612)          | (1,483,928)      
|Future income taxes                                                        | 76,030             | 219,466          
|Net earnings impact                                                        | 143,585            | 368,180          
|Basic net earnings per share                                               | -                  | 0.01             
|Diluted earnings per share                                                 | -                  | 0.01             

E-21

---



|Viracocha Energy Inc.                             
|--------------------------------------------------
|Notes to the Consolidated Financial
    Statements
|Three months ended December 31, 2004 and 2003     

The Company's asset retirement obligations result from net
ownership interests in oil and natural gas properties including well sites,
gathering systems and processing facilities. The Company estimates the total
undiscounted amount of cash flows (adjusted for inflation) required to settle
its asset retirement obligations is approximately $22.2 million which will be
incurred between 2004 to 2024. A credit-adjusted risk-free rate of 7 percent was
used to calculate the fair value of the asset retirement obligations.

A reconciliation of the asset retirement obligations is provided below:

|                               | Three months ended | Three months ended | Year ended       
|------------------------------ | ------------------ | ------------------ | -----------------
|Asset retirement obligations   | March 31, 2004     | March 31, 2003     | December 31, 2003
|                               | $                  | $                  | $                
|                               |                    |                    |                  
|Balance, beginning of period   | 7,551,306          | 2,679,589          | 2,679,589        
|Liabilities incurred in period | 121,106            | 2,729,731          | 4,732,669        
|Liabilities settled in period  | -                  | -                  | (48,704)         
|Accretion expense              | 90,971             | 46,938             | 187,752          
|Balance, end of period         | 7,763,383          | 5,456,258          | 7,551,306        

Full Cost Accounting -Effective January 1, 2004, the
Company adopted the new Canadian accounting guideline on oil and gas accounting.
This guideline impacts the calculation of the ceiling test (impairment test),
which requires cost centres be tested for recoverability using undiscounted
futures cash flows, which are determined by using forward indexed prices applied
to proved reserves. When the carrying amount of a cost centre is not
recoverable, the cost centre would be written down to its fair value, which is
estimated using accepted present value techniques. Under the previous method,
future net revenues for ceiling test purposes were based on proved reserves and
undiscounted end of period prices. Estimated future general and administrative
costs and financing charges associated with the future net revenues were
deducted in arriving at the "ceiling". The adoption of the new guideline at
January 1, 2004 has resulted in no change to net earnings, oil and natural gas
properties and equipment or other reported amounts in the December 31, 2003
financial statements.

Stock-based Compensation -Effective January 1, 2003, the
Company elected to prospectively adopt new transitional provisions to the
Canadian accounting standards on stock-based compensation which requires the use
of the fair value method for valuing stock option grants. Under this method,
compensation cost attributable to stock options granted to employees, officers,
and directors is measured at fair value at the grant date and expensed over the
vesting period with a corresponding increase to contributed surplus. Upon the
exercise of the stock options, consideration paid together with the amount
previously recognized in contributed surplus is recorded as an increase to share
capital. Pursuant to the transition rules, the expense recognized applies to
stock options granted on or after January 1, 2003. As a result of adopting this
amended standard, net earnings for the year ended December 31, 2003 decreased by
$181,850, which was recorded in the fourth quarter. For comparative purposes,
general and administrative expenses have been restated by $27,078 for the period
ended March 31, 2003. The Company has disclosed pro forma results for stock
options granted in 2002.

3.

The Company performed a ceiling test calculation at March 31,
2004 to assess the recoverable value of the petroleum and natural gas
properties. The oil and natural gas future prices are based on January 1, 2004
commodity price forecasts of the company's independent reserve evaluators. These
prices have been adjusted for commodity price differentials specific to the
Company. The following table summarizes the benchmark prices used in the ceiling
test calculation. Based on these assumptions, there was no impairment at March
31, 2004.

E-22

---



|Viracocha Energy Inc.                             
|--------------------------------------------------
|Notes to the Consolidated Financial
    Statements
|Three months ended December 31, 2004 and 2003     

|           |               |                  |                |              
|---------- | ------------- | ---------------- | -------------- | -------------
|           |               |                  | Edmonton Light |              
|           | WTI Oil       | Foreign Exchange | Crude Oil      | AECO Gas     
|Year       | ($US/bbl)     | Rate             | ($Cnd/bbl)     | ($Cnd/mmbtu) 
|2004       | 34.29         | 0.750            | 44.75          | 6.65         
|2005       | 29.00         | 0.750            | 37.75          | 5.55         
|2006       | 27.00         | 0.750            | 35.25          | 5.20         
|2007       | 25.00         | 0.750            | 32.50          | 5.00         
|2008       | 25.00         | 0.750            | 32.50          | 5.00         
|2009       | 25.00         | 0.750            | 32.50          | 5.00         
|2010       | 25.50         | 0.750            | 33.00          | 5.10         
|2011       | 25.75         | 0.750            | 33.50          | 5.20         
|2012       | 26.25         | 0.750            | 34.00          | 5.25         
|2013       | 26.25         | 0.750            | 34.50          | 5.35         
|2014       | 27.00         | 0.750            | 35.00          | 5.45         
|Escalate   |               |                  |                |              
|Thereafter | 1.5% per year |                  | 1.5% per year  | 1.5% per year

4.

The Company has a revolving operating demand loan credit
facility available up to $46.0 million bearing interest at prime plus a premium
ranging between 0% and 1.25% based on the Company's debt to cash flow ratio with
a Canadian bank. The credit facility also includes a $4.0 million non-revolving
development demand loan bearing interest at prime plus 0.75%. The credit
facility is secured by a $75 million fixed and floating charge debenture on the
assets of the Company.

Subsequent to March 31, 2004, a $3.0 million demand loan bearing interest at
prime plus 2.0% was added to the credit facility.

5.

The provision for future income taxes for the three months ended March 31,
2004 includes a liability reduction of approximately $355,000 related to a
substantively enacted 1.0 percent reduction to the Alberta income tax rate.

6.

At March 31, 2004 the Company had authorized an unlimited number of Class A
common shares, an unlimited number of Class B common shares and an unlimited
number of preferred shares.

The Company had the following shares outstanding at March 31, 2004:

|                                                                   | Number of  |           
|------------------------------------------------------------------ | ---------- | ----------
|Class A common shares                                              | Shares     | Amount ($)
|Balance at January 1, 2004                                         | 45,553,774 | 50,781,640
|Exercise of stock
    options                                      | 12,000     | 7,800     
|Balance at March 31, 2004                                          | 45,565,774 | 50,789,440
|                                                                   |            |           
|Share purchase warrants                                            | -          | 928,000   
|Equity portion of convertible
    debenture                        | -          | 533,157   
|                                                                   |            |           
|Total share capital                                                | 45,565,774 | 52,250,597
|                                                                   |            |           
|No Class B common shares or
    preferred shares have been issued. |            |           

E-23

---



|Viracocha Energy Inc.                             
|--------------------------------------------------
|Notes to the Consolidated Financial
    Statements
|Three months ended December 31, 2004 and 2003     

The Company had the following warrants outstanding at March 31, 2004:

|                                                                               |           | Weighted 
|------------------------------------------------------------------------------ | --------- | ---------
|                                                                               | Number of | Average  
|Warrants                                                                       | Warrants  | Price ($)
|Balance as at January 1, 2004 and March 31, 2004                               | 4,087,500 | 1.08     
|                                                                               |           |          
|The Company had the
    following stock options outstanding at March 31, 2004:
|                                                                               |           | Weighted 
|                                                                               | Number of | Average  
|Stock Options                                                                  | Options   | Price ($)
|Balance as at January 1, 2004                                                  | 4,434,300 | 1.59     
|Options granted                                                                | 10,000    | 2.50     
|Options exercised                                                              | (12,000)  | 0.65     
|Options cancelled                                                              | (25,000)  | 2.22     
|Balance as at March 31, 2004                                                   | 4,407,300 | 1.59     
|                                                                               |           |          
|Exercisable as at March 31, 2004                                               | 1,600,400 | 1.14     

7.

Effective January 1, 2003, the Company adopted the new
transitional provisions to the Canadian accounting standards on stock-based
compensation, which requires the use of the fair value method for valuing stock
options granted to employees, officers, and directors. Pursuant to the
transition rules, the expense recognized applies to stock options granted in
2003 and 2004. If the fair value method had been used for options granted in
2002, the Company's net earnings and net earnings per share for the three months
ended March 31, 2004 and 2003 would approximate the following pro forma amounts:

|                                | Three months ended | Three months ended
|------------------------------- | ------------------ | ------------------
|                                | March 31, 2004     | March 31, 2003    
|                                | $                  | $                 
|Compensation costs              | 62,934             | 140,584           
|Net earnings:                   |                    |                   
|As reported                     | 1,765,608          | 2,368,443         
|Pro forma                       | 1,702,674          | 2,227,859         
|Basic net earnings per share:   |                    |                   
|As reported                     | 0.04               | 0.06              
|Pro forma                       | 0.04               | 0.06              
|Diluted net earnings per share: |                    |                   
|As reported                     | 0.03               | 0.05              
|Pro forma                       | 0.03               | 0.05              

The fair value of each option granted is estimated on the date
of grant using the Black - Scholes option pricing model with the following
weighted average assumptions:

E-24

---



|Viracocha Energy Inc.                             
|--------------------------------------------------
|Notes to the Consolidated Financial
    Statements
|Three months ended December 31, 2004 and 2003     

|                        |                    |                   
|----------------------- | ------------------ | ------------------
|                        |                    |                   
|                        | Three months ended | Three months ended
|                        | March 31, 2004     | March 31, 2003    
|Fair value per option   | $1.18              | $0.75             
|Risk-free interest rate | 3.2%               | 4.2%              
|Expected life           | 4 years            | 4 years           
|Expected volatility     | 58%                | 42%               
|Dividend yield          | -                  | -                 











8. PER SHARE INFORMATION

The weighted average number of shares outstanding and net
earnings for the determination of basic and diluted per share amounts are as
follows:

|                                                                     | Three months ended | Three months ended
|-------------------------------------------------------------------- | ------------------ | ------------------
|                                                                     | March 31, 2004     | March 31, 2003    
|Numerator:                                                           |                    |                   
|Net earnings                                                         | $1,765,608         | $2,368,443        
|Adjustment for
    interest expense and amortization related to      |                    |                   
|convertible
    debentures, net of income tax                        | 41,132             | 53,941            
|Net earnings, adjusted                                               | $1,806,740         | $2,422,384        
|                                                                     |                    |                   
|Denominator:                                                         |                    |                   
|Weighted-average shares used to calculate basic EPS                  | 45,563,796         | 39,456,647        
|Dilutive effect of options,
    warrants, and convertible debentures | 6,919,838          | 6,112,235         
|Diluted number of shares                                             | 52,483,634         | 45,568,882        

9. PHYSICAL HEDGE CONTRACTS

The Company uses forward physical contracts to hedge exposure
to commodity prices. Gains and losses on oil and natural gas transactions are
reported as adjustments to oil and natural gas revenue when the related
production is delivered and sold. The estimated fair market value at March 31,
2004, had the contracts been settled at that time, would have been a loss of
$2.0 million.

At March 31, 2004, the Company held certain physical hedges
for a portion of its oil production. Light oil contracts are referenced to the
West Texas Intermediate ("WTI") price. The terms of the physical contracts are
as follows:

|                            | Volume | WTI    
|--------------------------- | ------ | -------
|Term                        | Bbls/d | $US/bbl
|Jan 1, 2004 to Dec 31, 2004 | 500    | 26.00  
|Apr 1, 2004 to Jun 30, 2004 | 500    | 31.25  
|Apr 1, 2004 to Jun 30, 2004 | 500    | 32.15  
|Jul 1, 2004 to Sep 30, 2004 | 700    | 31.03  

The Company is exposed to foreign currency fluctuations as crude prices
received for a portion of its contracts entered into subsequent to year-end are
referenced to U.S. dollar denominated prices.

Other than as outlined above, the Company's oil and natural gas production is
marketed and sold on the spot market to area aggregators based on daily spot
prices that are adjusted for product quality and transportation costs.

E-25

---



|Viracocha Energy Inc.                             
|--------------------------------------------------
|Notes to the Consolidated Financial
    Statements
|Three months ended December 31, 2004 and 2003     

The Company fixed the price of electricity on 2.5 megawatts
per hour ("Mw/h") from January 1, 2004 through December 31, 2005 at a price of
$45.875/Mw/h. The estimated market value at March 31, 2004, had the contract
been settled at that time, would have been a gain of $231,500.

10. SUBSEQUENT EVENT

On April 6, 2004, Provident Energy Trust (the "Trust"), and
the Company entered into an arrangement agreement pursuant to which the Trust
agreed to acquire the Company other than certain producing properties and
undeveloped acreage in Alberta that are to be distributed to a newly formed
corporation, Chamaelo Energy Inc. ("Chamaelo"). Under the terms of the
agreement, each Viracocha shareholder will receive 0.248 of a Trust unit and
0.10 of a Chamaelo share in exchange for each Viracocha share held. The total
aggregate transaction value is approximately $208 million comprised of the
following:

> (i) Trust units - $153 million based on the 30 day weighted
>   average trading price at the date of the proposed agreement. 
>   (ii) Chamaelo shares - $14 million based on the estimated net asset value.
>   (iii) Debt assumed by Trust - $41 million estimated net debt and working
>   capital after dilution.

Completion of the proposed transactions under the agreement
will result in the issuance of 5.7 million Chamaelo common shares as
consideration for the transfer of the properties to Chamaelo. Pursuant to the
agreement, 56.8 million fully diluted common shares of Viracocha, including the
conversion of all stock options, warrants, and convertible debentures into
common shares, will be exchanged for Chamaelo common shares on a one for ten
basis. As Chamaelo and Viracocha are deemed to be related parties, the net
assets acquired by Chamaelo will be recorded at Viracocha's net book value of
approximately $13.6 million. The agreement is subject to shareholder approval on
or about May 27, 2004.

E-26

---



|Viracocha Energy Inc.                             
|--------------------------------------------------
|Notes to the Consolidated Financial
    Statements
|Three months ended December 31, 2004 and 2003     

SCHEDULE F

FINANCIAL STATEMENTS OF 
BREITBURN ENERGY COMPANY LLC

(in U.S. dollars except where otherwise
indicated)



BreitBurn Energy Company LLC 
and Subsidiaries







F - 1

---

Report of Independent Auditors
To the Board of Directors and Members of 
BreitBurn Energy Company LLC:
In our opinion, the accompanying consolidated balance sheets
and the related consolidated statements of operations, comprehensive income,
members' equity and cash flows present fairly, in all material respects, the
financial position of BreitBurn Energy Company LLC and subsidiaries (the
"Company") at December 31, 2003 and 2002, and the results of their operations
and their cash flows for the years then ended in conformity with accounting
principles generally accepted in the United States of America. These financial
statements are the responsibility of the Company's management; our
responsibility is to express an opinion on these financial statements based on
our audits. We conducted our audits of these statements in accordance with
auditing standards generally accepted in the United States of America, which
require that we plan and perform the audit to obtain reasonable assurance about
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, assessing the accounting principles
used and significant estimates made by management, and evaluating the overall
financial statement presentation. We believe that our audits provide a
reasonable basis for our opinion.
The accompanying consolidated financial statements have been
prepared assuming that the Company will continue as a going concern. As
discussed in Note 2 to the financial statements, the Company has significant
debt obligations and mandatorily redeemable preferred shares maturing in 2004
that raise substantial doubt about its ability to continue as a going concern.
Management's plans in regard to this matter are also described in Note 2. The
consolidated financial statements do not include any adjustments that might
result from the outcome of this uncertainty.
As discussed in Note 2 to the consolidated financial
statements, the Company changed its method of accounting for asset retirement
obligations in connection with the adoption of Statement of Financial Accounting
Standards No. 143, Accounting for Asset Retirement Obligations, in 2003.
Comments by U.S. Auditors for Canadian Readers on U.S. - Canada Reporting
Difference
Generally accepted auditing standards ("GAAS") in the United
States expressly permit the reference in the auditor's report to the entity's
ability to continue as a going concern. Additionally, GAAS in the United States
expressly requires the reference to a change in accounting policies where the
impact on the financial statements is significant. Canadian GAAS does not permit
such references. Such reference in a U.S. audit report is not to be construed as
a qualification or a reservation of the opinion, but rather an emphasis of
certain matters disclosed within the financial statements. Other than this
reporting difference, the form and content of the U.S. GAAS audit report is
substantially the same as a Canadian GAAS audit report.
In addition, auditing standards generally accepted in the United States are
substantially equivalent to Canadian GAAS.
(Signed) PricewaterhouseCoopers LLP 
Los Angeles, California 
March 26, 2004





F - 2

---



|BreitBurn Energy Company LLC                                                            
|----------------------------------------------------------------------------------------
|and Subsidiaries                                                                        
|Consolidated Balance Sheets                                                             
|December 31, 2003 and 2002                                                              
|                                                                                        
|Assets                                                                                  
|Current assets                                                                          
|Cash and cash
    equivalents                                                           
|Accounts receivable                                                                     
|Trade, net of allowance for doubtful accounts of $42,054 and $49,097                    
|as of December 31, 2003 and 2002, respectively                                          
|Other receivable                                                                        
|Prepaid expenses                                                                        
|Hedge asset                                                                             
|Deposits and other                                                                      
|                                                                                        
|Total current assets                                                                    
|                                                                                        
|Property, plant and equipment, net                                                      
|                                                                                        
|Other assets                                                                            
|Abandonment
    bonds                                                                   
|Debt issuance
    costs, net of accumulated amortization of $910,088 and $642,032       
|as of December 31, 2003 and 2002, respectively                                          
|Investment in
    affiliates                                                            
|Notes
    receivable - related parties                                                  
|Hedge asset                                                                             
|Other
    long-term assets                                                              
|                                                                                        
|                                                                                        
|                                                                                        
|Total assets                                                                            
|                                                                                        
|                                                                                        
|Liabilities and Members' Equity                                                         
|Current liabilities                                                                     
|Accounts payable and
    accrued liabilities                                            
|Hedge liability                                                                         
|Derivative
    settlements payable                                                      
|Liability due to
    disposal of non-operating interest                                 
|Senior subordinated
    debt due to member                                              
|Current portion of
    long-term debt                                                   
|                                                                                        
|Total current liabilities                                                               
|                                                                                        
|Long-term debt                                                                          
|Senior subordinated long-term debt due to
    member                                    
|Abandonment liability                                                                   
|Hedge liability                                                                         
|Liability due to disposal of non-operating
    interest                                 
|Other long-term liability                                                               
|                                                                                        
|Total liabilities                                                                       
|                                                                                        
|Commitments and contingencies (Note 8)                                                  
|                                                                                        
|Redeemable preferred shares (no par;
    4,100,000 shares authorized;                   
|3,646,519 shares
    issued and outstanding)                                            
|                                                                                        
|Members' equity: (Class A: no par; 12,169,318
    shares authorized, issued and         
|outstanding; Class
    B: no par; 959,625 (2003) and 1,000,000 (2002) shares authorized,
|918,750 (2003)                                                                          
|and 867,125 (2002);
    shares issued and outstanding)                                  
|Accumulated other comprehensive loss                                                    
|                                                                                        
|Total members' equity                                                                   
|                                                                                        
|Total liabilities and members' equity                                                   

F - 3

---



|BreitBurn Energy
    Company LLC                                        |                  |                 
|----------------------------------------------------------------------- | ---------------- | ----------------
|and Subsidiaries                                                        |                  |                 
|Consolidated
    Statements of Operations                               |                  |                 
|For the Years Ended December 31, 2003
    and 2002                      |                  |                 
|                                                                        | 2003             | 2002            
|Revenues                                                                |                  |                 
|Oil and gas sales, net
    of hedging loss of $7,289,915 and $2,961,363 |                  |                 
|for the years ended December 31, 2003 and 2002, respectively            | $
    30,460,589 | $
    35,166,396
|Gain on sale of assets                                                  | 10,824,108       | 2,266,005       
|Equity earnings in
    affiliate                                        | 233,429          | 99,197          
|Operating fees                                                          | 662,778          | 470,621         
|                                                                        |                  |                 
|                                                                        | 42,180,904       | 38,002,219      
|                                                                        |                  |                 
|Operating costs and
    expenses                                        |                  |                 
|Gas and NGL purchases                                                   | 94,758           | 163,297         
|Lease operating
    expenses                                            | 14,412,728       | 14,610,378      
|Production and
    property taxes                                       | 1,178,187        | 1,468,702       
|Depletion,
    depreciation and amortization of proved oil and          |                  |                 
|gas properties                                                          | 3,413,708        | 4,359,333       
|Exploration and
    acquisition expense                                 | 18,753           | 226,298         
|General and
    administrative expenses                                 | 4,170,969        | 3,302,382       
|                                                                        |                  |                 
|                                                                        | 23,289,103       | 24,130,390      
|                                                                        |                  |                 
|Operating income                                                        | 18,891,801       | 13,871,829      
|                                                                        |                  |                 
|Other (income) expense                                                  |                  |                 
|Interest expense                                                        | 2,693,070        | 3,208,831       
|Interest income                                                         | (48,051)         | (22,075)        
|Amortization of debt
    issuance costs                                 | 268,056          | 268,055         
|Depreciation of
    non-oil and gas assets                              | 204,238          | 163,903         
|Gain on sale of
    financial instruments                               | -                | (626,621)       
|Gain on change in fair
    value of derivative instruments              | -                | (926,153)       
|Other expense                                                           | 375,900          | 523,139         
|Other income                                                            | (60,341)         | (108,143)       
|                                                                        |                  |                 
|                                                                        | 3,432,872        | 2,480,936       
|                                                                        |                  |                 
|Income from continuing operations                                       | 15,458,929       | 11,390,893      
|                                                                        |                  |                 
|Discontinued
    operations                                             |                  |                 
|Loss from operations
    of Beta interest                               | -                | (405,799)       
|Loss on disposal of
    Beta interest                                   | -                | (6,203,041)     
|                                                                        |                  |                 
|Loss from discontinued operations                                       | -                | (6,608,840)     
|                                                                        |                  |                 
|Cumulative effect of
    accounting change                              | 1,653,303        | -               
|                                                                        |                  |                 
|Net income                                                              | $ 17,112,232     | $ 4,782,053     

F - 4

---



|BreitBurn Energy Company LLC                        |              |              
|--------------------------------------------------- | ------------ | -------------
|and Subsidiaries                                    |              |              
|Consolidated Statements of
    Comprehensive Income |             
|For the Years Ended December 31, 2003 and 2002      |              |              
|                                                    | 2003         | 2002         
|                                                    |              |              
|Net income                                          | $ 17,112,232 | $ 4,782,053  
|                                                    |              |              
|Change in fair value of derivative
    instruments  | (4,654,885)  | (8,432,473)  
|                                                    |              |              
|Comprehensive income (loss)                         | $ 12,457,347 | $ (3,650,420)
|                                                    |              |              

F - 5

---



|BreitBurn Energy Company LLC                      
|--------------------------------------------------
|and Subsidiaries                                  
|Consolidated Statements of
    Members' Equity    
|For the Years Ended December 31, 2003 and 2002    
|                                                  
|                                                  
|                                                  
|                                                  
|                                                  
|Balance at December 31, 2001                      
|                                                  
|Issuance of Class B common shares                 
|Net income                                        
|Redeemable preferred stock accretion              
|Redeemable preferred cash dividend                
|Change in fair value of derivative
    instruments
|                                                  
|Balance at December 31, 2002                      
|                                                  
|Issuance of Class A common shares                 
|Issuance of Class B common shares                 
|Purchase of Class B common shares                 
|Net income                                        
|Redeemable preferred stock accretion              
|Redeemable preferred stock cash dividend          
|Accrued preferred stock dividend                  
|Change in fair value of derivative
    instruments
|                                                  
|Balance at December 31, 2003                      

F - 6

---



|BreitBurn Energy
    Company LLC                                |   |              |   |             
|--------------------------------------------------------------- | - | ------------ | - | ------------
|and Subsidiaries                                                |   |              |   |             
|Consolidated
    Statements of Cash Flows                       |   |              |   |             
|For the Years Ended December 31, 2003
    and 2002              |   |              |   |             
|                                                                |   | 2003         |   | 2002        
|Cash flows from
    operating activities                        |   |              |   |             
|Net income                                                      | $ | 17,112,232   | $ | 4,782,053   
|Adjustments to
    reconcile net income to net cash provided by |   |              |   |             
|operating
    activities                                        |   |              |   |             
|Cumulative effect of SFAS No. 143 adoption                      |   | (1,653,303)  |   | -           
|Depletion, depreciation and amortization                        |   | 3,617,946    |   | 4,523,236   
|Amortization of debt issuance costs                             |   | 268,056      |   | 268,055     
|Equity
    earnings in affiliate                                |   | (233,429)    |   | (99,197)    
|Distributions received from affiliates                          |   | 314,103      |   | 91,810      
|(Gain)
    loss on sales of assets                              |   | (10,824,108) |   | 3,310,415   
|Changes
    in working capital                                  |   |              |   |             
|(Increase) decrease in accounts receivable                      |   | (253,899)    |   | 390,964     
|(Increase) decrease in prepaid expenses, deposits and other     |   | 112,698      |   | (1,106,962) 
|Decrease in accounts payable and accrued liabilities            |   | (1,834,512)  |   | (1,955,254) 
|                                                                |   |              |   |             
|Net cash provided by operating activities                       |   | 6,625,784    |   | 10,205,120  
|                                                                |   |              |   |             
|Cash flows from
    investing activities                        |   |              |   |             
|Expenditures for oil
    and gas properties                     |   | (12,791,833) |   | (20,618,723)
|Expenditures for land                                           |   | (16,870)     |   | (2,190,780) 
|Disposal of Beta
    nonoperating interest                      |   | -            |   | (5,000,000) 
|Expenditures for other
    non-oil and gas assets               |   | -            |   | (115,090)   
|Proceeds from sales of
    assets                               |   | 34,533,518   |   | 7,760,000   
|Proceeds from sales of
    financial instruments                |   | -            |   | 903,507     
|Closing cost                                                    |   | (731,670)    |   | -           
|Contributions made to
    affiliate                             |   | (353,329)    |   | -           
|Additions to non-oil
    and gas assets                         |   | (19,571)     |   | -           
|                                                                |   |              |   |             
|Net cash provided by (used in) investing activities             |   | 20,620,245   |   | (19,261,086)
|                                                                |   |              |   |             
|Cash flows from
    financing activities                        |   |              |   |             
|Proceeds from
    long-term debt                                |   | 56,500,000   |   | 64,000,000  
|Payments on long-term
    debt                                  |   | (81,500,000) |   | (51,800,000)
|Purchase of Class B
    common shares                           |   | (17,226)     |   | -           
|Cash preferred stock
    dividends                              |   | (1,823,259)  |   | (3,646,519) 
|Debt issuance costs                                             |   | (14,179)     |   | -           
|                                                                |   |              |   |             
|Net cash (used in)
    provided by financing activities         |   | (26,854,664) |   | 8,553,481   
|                                                                |   |              |   |             
|Net increase
    (decrease) in cash and cash equivalents        |   | 391,365      |   | (502,485)   
|                                                                |   |              |   |             
|Cash and cash
    equivalents                                   |   |              |   |             
|Beginning of year                                               |   | 323,205      |   | 825,690     
|                                                                |   |              |   |             
|End of year                                                     | $ | 714,570      | $ | 323,205     

F - 7

---



|BreitBurn Energy Company LLC 
    and Subsidiaries 
    Notes to Consolidated Financial Statements
|--------------------------------------------------------------------------------------------------

1.         
Organization and Description of Operations

> BreitBurn Energy Company LLC (the "Company"), organized
>   under the State of California Beverly-Killea Limited Liability Company Act,
>   was formed on March 5, 1997, and will expire on or before March 5, 2027. The
>   Company is engaged in the acquisition, exploration, development and production
>   of oil and gas properties, in the States of California, Texas and Wyoming. For
>   the years ended December 31, 2003 and 2002, 98% and 97% of the Company's
>   revenues were derived from its California properties, respectively.
>   On March 26, 2003, the Company formed BreitBurn Energy
>   Partners I, L.P. (the "Partnership"), a Texas limited partnership, which will
>   expire on or before April 1, 2023. Operations of the Partnership began on May
>   5, 2003. BEP (GP) I, LP, a wholly owned subsidiary of the Company, is a 1%
>   general partner in the Partnership. TIFD III-X, LLC, a subsidiary of GE
>   Capital, is the limited partner with a 99% partnership interest. The
>   Partnership is engaged in the acquisition, exploration, development and
>   production of oil and gas properties.

2.         
Significant Accounting Policies

> Principles of Consolidation
>   The consolidated financial statements include the accounts
>   of the Company and its wholly owned subsidiaries. Investments in affiliated
>   companies with a 20% or greater ownership interest, and in which the Company
>   does not have control, are accounted for on the equity basis. Investments in
>   affiliated companies with less than a 20% ownership interest, and in which the
>   Company does not have control, are accounted for at cost. The effects of all
>   intercompany transactions have been eliminated.
>   Revenue Recognition
>   Oil and gas revenue is recognized when title passes to the
>   customer.
>   Cash and Cash Equivalents
>   Cash and cash equivalents include short-term investments
>   with an original maturity of three months or less.
>   Oil and Gas Properties
>   The Company follows the successful efforts method of
>   accounting. Lease acquisition and development costs (tangible and intangible)
>   incurred, including internal acquisition costs, relating to proved oil and gas
>   properties are capitalized. Delay and surface rentals are charged to expense
>   as incurred. Dry hole costs incurred on exploratory wells are expensed. Dry
>   hole costs associated with developing proved fields are capitalized.
>   Geological and geophysical costs related to exploratory operations are
>   expensed as incurred.

F - 8

---



|BreitBurn Energy Company LLC 
    and Subsidiaries 
    Notes to Consolidated Financial Statements
|--------------------------------------------------------------------------------------------------

2.

> Oil and Gas Properties (Continued)
>   Upon sale or retirement of proved properties, the cost
>   thereof and the accumulated depletion, depreciation and amortization are
>   removed from the accounts and any gain or loss is recognized in the statements
>   of operations and comprehensive income. Maintenance and repairs are charged to
>   operating expenses. Depletion, depreciation and amortization of proved oil and
>   gas properties, net of any anticipated proceeds from equipment salvage and
>   sale of surface rights, as well as the estimated cost of future abandonment
>   and restoration of well sites and associated facilities, are computed on a
>   property-by-property basis and recognized using the units-of-production
>   method.
>   The Company's policy is to capitalize interest on significant drilling
>   projects based on its incremental borrowing rate.
>   Buildings and Non-Oil and Gas Assets
>   Buildings and non-oil and gas assets are recorded at cost and depreciated
>   using the straight-line method over their estimated useful lives, which range
>   from 3 to 30 years.
>   Debt Issuance Costs
>   The costs incurred to obtain financing have been capitalized. Debt issuance
>   costs are amortized using the straight-line method over the life of the debt.
>   Concentration of Credit Risk
>   The Company maintains its cash accounts primarily with a
>   single bank and invests cash in money market accounts, which the Company
>   believes to have minimal risk. As operator of jointly owned oil and gas
>   properties, the Company sells oil and gas production to U.S. oil and gas
>   purchasers, and pays vendors on behalf of joint owners for oil and gas
>   services. Both purchasers and joint owners are located primarily in the
>   Western United States. The risk of nonpayment by the purchasers or joint
>   owners is considered minimal and has been considered in the Company's
>   allowance for doubtful accounts.
>   At December 31, 2003 and 2002, 66% and 75%, respectively, of the Company's
>   trade receivables were due from a large domestic refiner of crude oil.
>   Environmental Concerns
>   The Company is continually taking actions it believes
>   necessary in its operations to ensure conformity with applicable federal,
>   state and local environmental regulations. As of December 31, 2003, the
>   Company has not been fined or cited for any environmental violations, which
>   would have a material adverse effect upon capital expenditures or operating
>   results of the Company.

F - 9

---



|BreitBurn Energy Company LLC 
    and Subsidiaries 
    Notes to Consolidated Financial Statements
|--------------------------------------------------------------------------------------------------

2.

> Stock Compensation
>   The employee stock ownership plan is accounted for under
>   the provisions of APB Opinion No. 25, "Accounting for Stock Issued to
>   Employees." APB No. 25 requires the use of the intrinsic value method, which
>   measures compensation cost as the excess, if any, of the fair value of the
>   stock at grant over the amount an employee must pay to acquire the stock. SFAS
>   No. 123, "Accounting for Stock-Based Compensation," established accounting and
>   disclosure requirements using a fair-value based method of accounting for
>   stock-based employee compensation plans. The Company has elected to retain its
>   current method of accounting as described above and has adopted the disclosure
>   requirements of SFAS No. 123.
>   Impairment of Assets
>   Oil and gas properties are regularly assessed for possible
>   impairment, generally on a field-by-field basis where applicable, using the
>   estimated undiscounted future cash flows of each field. Impairment losses are
>   recognized when the estimated undiscounted future cash flows are less than the
>   current net book values of the properties in a field.
>   Impairment charges are also made for other long-lived assets when it is
>   determined that the carrying values of the assets may not be recoverable.
>   The Company did not record an impairment charge in 2003 or 2002.
>   Adoption of SFAS No. 143
>   In June 2001, the Financial Accounting Standards Board ("FASB")
>   issued SFAS No. 143, "Accounting for Asset Retirement Obligations." This
>   statement requires that the Company recognize liabilities related to the legal
>   obligations associated with the retirement of its tangible long-lived assets
>   at fair values in the periods in which the obligations are incurred (typically
>   when the assets are installed). These obligations include the plugging and
>   abandonment of oil and gas wells and facilities and the closure and site
>   restoration of certain facilities.
>   Prior to January 1, 2003, the Company was required, under
>   SFAS No. 19, "Financial Accounting and Reporting by Oil and Gas Producing
>   Companies," to accrue its abandonment and restoration costs ratably over the
>   productive lives of its assets. The Company previously used the
>   units-of-production method to accrue these costs. SFAS No. 19 resulted in
>   higher costs being accrued early in the fields' lives when production was at
>   its highest levels and abandonment and restoration costs accruals were matched
>   with the revenues as oil and gas were produced.
>   Under SFAS No. 143, when the liabilities for asset
>   retirement obligations are initially recorded at fair values, capital costs of
>   the related assets will be increased by equal corresponding amounts. Over
>   time, changes in the present value of the liabilities will be accreted and
>   expensed and the capitalized asset costs will be depreciated over the useful
>   lives of the corresponding assets. Because SFAS No. 143 requires the use of
>   interest accretion for revaluing asset retirement obligation liabilities as a
>   result of the passage of time, associated accretion costs will be higher near
>   the end of the fields' lives when oil and gas production and related revenues
>   are at their lowest levels.

F - 10

---



|BreitBurn Energy Company LLC 
    and Subsidiaries 
    Notes to Consolidated Financial Statements
|--------------------------------------------------------------------------------------------------

2.

> Adoption of SFAS No. 143 (Continued)
>   In accordance with the provisions of SFAS No. 143 the
>   company recorded a cumulative-effect adjustment of $1,653,303 as the
>   cumulative effect of an accounting change related to the adoption of SFAS No.
>   143. Had SFAS No. 143 been adopted on January 1, 2002, the liability would
>   have been $741,483 at January 1, 2002 and $709,591 at December 31, 2002.
>   Derivative Instruments
>   SFAS No. 133, "Accounting for Derivative Instruments and
>   Hedging Activities", as amended establishes accounting and reporting standards
>   for derivative instruments, including certain derivative instruments embedded
>   in other contracts, and hedging activities. It requires the recognition of all
>   derivative instruments as assets or liabilities in the Company's balance sheet
>   and measurement of those instruments at fair value. The accounting treatment
>   of changes in fair value is dependent upon whether or not a derivative
>   instrument is designated as a hedge and if so, the type of hedge. For
>   derivatives designated as cash flow hedges, changes in fair value are
>   recognized in other comprehensive income; to the extent the hedge is
>   effective, until the hedged item is recognized in earnings. Hedge
>   effectiveness is measured based on the relative changes in fair value between
>   the derivative contract and the hedged item over time. Any change in fair
>   value resulting from ineffectiveness, as defined by SFAS No.133, is recognized
>   immediately in earnings.
>   Income Taxes
>   The Company is not subject to income tax as it has elected
>   to be taxed as a partnership for income tax reporting purposes and the income
>   or loss of the Company is included in the income tax returns of the individual
>   members.
>   Use of Estimates
>   The preparation of financial statements in conformity with
>   accounting principles generally accepted in the United States of America
>   requires management to make estimates and assumptions that affect the reported
>   amounts of assets and liabilities and disclosure of contingent assets and
>   liabilities at the date of the financial statements and the reported amounts
>   of revenues and expenses during the reporting period. Actual results could
>   differ from those estimates.
>   The financial statements are based on a number of
>   significant estimates including oil and gas reserve quantities, which are the
>   basis for the calculation of depletion, depreciation, amortization and
>   impairment of oil and gas properties.
>   Reclassifications
>   Certain items in the prior year financial statements have been reclassified
>   to conform to the 2003 presentation.

F - 11

---



|BreitBurn Energy Company LLC 
    and Subsidiaries 
    Notes to Consolidated Financial Statements
|--------------------------------------------------------------------------------------------------

2.

> Management's Plan
>   The accompanying consolidated financial statements have
>   been prepared on a going concern basis, which contemplates the realization of
>   assets and the satisfaction of liabilities in the normal course of business.
>   The Company has debt obligations with scheduled maturities during 2004
>   totaling $38.9 million. Additionally, as more fully described in Note 7, the
>   Company has redeemable preferred stock subject to mandatory redemption on
>   December 31, 2004 totaling $38.7 million. These matters raise substantial
>   doubt about the Company's ability to continue as a going concern. The
>   consolidated financial statements do not include any adjustments that might
>   result from the outcome of these uncertainties.
>   Management has obtained and is currently evaluating offers
>   for several alternative financing arrangements that provide the Company with
>   the ability to meet these obligations. Management intends to select the option
>   that most closely fits the long-term strategic plans of the Company. Although
>   no assurances can be given, management is confident that the restructuring of
>   the Company's outstanding debt and redeemable preferred stock will enable the
>   company to continue as a going concern.

3.

> The carrying value of cash, accounts receivable, accounts
>   payable and accrued liabilities are carried at cost, which approximates their
>   fair market value because of the short-term maturity of these instruments. The
>   fair value of the Company's long-term debt approximates the carrying value due
>   to the market-based nature of the line of credit.
>   The Company periodically hedges a portion of its oil and
>   gas production through futures and swap agreements. The purpose of the hedge
>   is to stabilize its exposure to commodity price risk in the volatile
>   environment of oil and gas prices. All of the Company's swap agreements in
>   place at December 31, 2003 and 2002 are designated as cash flow hedges. At
>   December 31, 2003 and 2002 cash flow hedges consisted of swap contracts and
>   put options to hedge between 500 and 4,000 barrels of oil production per day
>   from January 1, 2003 through December 31, 2006. These contracts have a swap
>   price range of $23.03 to $28.13 per barrel. The net fair values of these
>   contracts at December 31, 2003 and 2002 are losses of approximately $8,360,000
>   and $2,922,000, respectively.
>   The Company uses interest-rate swaps to convert a portion
>   of its variable-rate debt to fixed rates. At December 31, 2003 and 2002, the
>   notional principal amount of the Company's interest-rate swaps ranged from
>   $35,000,000 to $45,000,000, respectively. The net gain or loss resulting from
>   the interest-rate swap was not significant to the Company and is recorded in
>   interest expense.

F - 12

---



|BreitBurn Energy Company LLC 
    and Subsidiaries 
    Notes to Consolidated Financial Statements
|--------------------------------------------------------------------------------------------------

4.

> Property, plant and equipment at December 31 was as follows:

|                                                                                                         | 2003          | 2002         
|-------------------------------------------------------------------------------------------------------- | ------------- | -------------
|Proved oil and gas properties, successful
      efforts                                                  |               |              
|method                                                                                                   | $ 110,647,375 | $ 121,244,033
|Land                                                                                                     | 1,990,384     | 1,973,514    
|Buildings                                                                                                | 274,483       | 274,483      
|Non-oil and gas assets                                                                                   | 1,157,493     | 1,137,922    
|Work in progress - oil and gas assets                                                                    | -             | 3,106,059    
|                                                                                                         |               |              
|                                                                                                         | 114,069,735   | 127,736,011  
|Less accumulated depletion, depreciation
      and                                                       |               |              
|amortization                                                                                             | (17,223,795)  | (17,181,135) 
|                                                                                                         |               |              
|Property, plant and equipment, net                                                                       | $ 96,845,940  | $ 110,554,876
|                                                                                                        
|Interest capitalized to oil
      and gas properties was $0 and $468,550 in 2003 and 2002, respectively.

5.

> Notes payable consist of the following:

|Type of          | Interest | Interest  |   |            |   |            |               
|---------------- | -------- | --------- | - | ---------- | - | ---------- | --------------
|Note             | Rate     | Payment   |   | 2003       |   | 2002       | Maturity      
|                 |          |           |   |            |   |            |               
|Credit Agreement | Various  | Quarterly | $ | 6,400,000  | $ | 3,400,000  | May 5, 2004   
|Credit Agreement | Various  | Monthly   |   | 31,000,000 |   | 59,000,000 | May 5, 2004   
|Promissory Note  | Various  | Quarterly |   | 1,500,000  |   | 1,500,000  | March 25, 2004
|                 |          |           |   |            |   |            |               
|                 |          |           | $ | 38,900,000 | $ | 63,900,000 |               

The Company has a Credit Agreement (the "Agreement") with
Wells Fargo Bank (Texas), N.A., Bank of Scotland and U.S. Bank National
Association. Funds advanced under the Agreement are collateralized by the
Company's oil and gas producing properties and bear interest at either an
adjusted London Interbank Offered Rate ("LIBOR") plus 1.25% to 2% or Wells Fargo
Bank's base rate plus .25% to 1.00% (3.1% and 5.0%, respectively, at December
31, 2003). The applicable basis point increase over the adjusted LIBOR or the
Wells Fargo Bank's base rate increases as the Company's borrowings under the
Agreement approach the available borrowing base.

F - 13

---



|BreitBurn Energy Company LLC 
    and Subsidiaries 
    Notes to Consolidated Financial Statements
|--------------------------------------------------------------------------------------------------

5.

> The initial authorized borrowing base was established at
>   $50 million. The maximum loan amount under the Agreement is $150 million. The
>   borrowing base at December 31, 2003 under the Agreement was $40 million.
>   Outstanding borrowings subject to the adjusted LIBOR rate and base rate
>   borrowing were $31.0 million and $6.4 million, respectively, at December 31,
>   2003. In accordance with the Agreement, the entire amount outstanding at
>   December 31, 2003 is classified as short-term. The Agreement requires, among
>   other things, that the Company maintain at least a 1 to 1 current ratio and a
>   minimum adjusted cash flow to interest ratio of 1.25 to 1 as of December 31,
>   2003, all as defined in the Agreement.
>   The Company has a 10%, $1.5 million promissory note dated
>   March 25, 1997 and maturing on March 25, 2004 (the "Promissory Note") due to
>   Energy Company of America ("ECA"). The borrowing rate until maturity is 10%,
>   adjusted for the wellhead oil price received by the Company, which differs
>   from a set price of $20.79 per barrel (13.47% at December 31, 2003).
>   The Promissory Note is collateralized by deeds of trust on
>   the Company's interest in certain real estate property and all oil and gas
>   interests in the property and an executive right permitting the encumbrance of
>   the property to collateralize a bond or letter of credit in accordance with
>   certain provisions of the original sale and purchase agreement for oil and gas
>   properties purchased from Occidental Petroleum Company ("OXY"). At maturity or
>   any other time the Company elects and is consented to by ECA, ECA shall have
>   the option to convert the outstanding principal and interest into either a
>   working interest in the OXY properties or proportionate shares of the Company.
>   The remaining debt of $38,900,000 matures in 2004.

6.

> Members' equity at December 31, 2003 consists of 12,169,318
>   Class A common shares and 918,750 Class B common shares or units of membership
>   interest, as defined in California Corporations Code section 17001(z). An
>   individual capital account is maintained for each member and consists of that
>   member's capital contribution plus that member's share of profits and losses,
>   less any distributions, in accordance with applicable provisions of Internal
>   Revenue Code and Regulations. The profits and losses of the Company and all
>   items of income, gain or loss are allocated to a member in accordance with
>   that member's percentage interest calculated by the number of shares that
>   member holds in relation to the total number of shares issued.
>   Pursuant to the Company's operating agreement, the Company issued 334,698
>   Class A common shares on June 3, 2003 to EnCap. No consideration was received
>   due to this issue.



F - 14

---



|BreitBurn Energy Company LLC 
    and Subsidiaries 
    Notes to Consolidated Financial Statements
|--------------------------------------------------------------------------------------------------

6.

> In 1997, the Board of Directors of the Company approved an
>   Employee Stock Ownership Plan (the "Plan") that covers key employees and board
>   members. The purpose of the plan is to provide an incentive to expand and
>   improve the profits and prosperity of the Company, and to assist the Company
>   in attracting and retaining key personnel through the grant of shares of the
>   Company's common stock. The Board of Directors of the Company has authorized 1
>   million Class B common shares for the Plan. The Class B common shares have no
>   voting rights. The stock issued under the Plan represents a profits interest
>   only, as defined in Revenue Procedure 93-27, 1993-2 C.B. 343 (1993), and is
>   granted without payment of any cash consideration. The Plan is effective for
>   ten years and termination of the Plan will not affect any stock previously
>   granted. The Company may repurchase the stock granted to such participant at a
>   purchase price and under terms defined in the Plan agreement. At December 31,
>   2003, the Company had 918,750 Class B common shares issued and outstanding
>   under the Plan. No compensation expense has been recognized for the Plan in
>   2003 or 2002.

7.

> In 1998, the Company issued 167,349 Class A common shares
>   and 3,000,000 preferred shares for $29,150,000. The preferred shares do not
>   have any voting rights. The preferred shareholders are entitled to receive
>   distributions from the Company at the annual rate of 10% of the redemption
>   amount of $30,000,000 plus any dividends previously paid in-kind.
>   Distributions on the preferred shares are payable semi-annually on December 3
>   and June 3 of each year commencing on December 3, 1998. The first four
>   dividends were paid in-kind at the option of the Company. Distributions are
>   cumulative and accrue whether or not declared and whether or not there will be
>   funds legally available for the payment thereof. For the years ended December
>   31, 2003 and 2002, the Company paid cash dividends in the amounts of
>   $1,823,259 and $3,646,519, respectively. The Company had a dividend due in
>   December 2003 that the Company contractually modified to come due March 31,
>   2004 in the form of an in-kind dividend payment.
>   The Company has the option to redeem the preferred shares
>   at any time, and shares are subject to mandatory redemption on December 31,
>   2004, at a price per share equal to the redemption amount as defined by the
>   agreement.

8.

> The Company has surety bonds to provide $4,858,280 of
>   coverage to OXY in connection with a purchase agreement entered into by
>   Westside in 1993 for the purchase of oil and gas producing properties.
>   The Company has accrued an abandonment liability related to
>   the abandonment of certain oil and gas properties of $708,764 and $2,303,591
>   at December 31, 2003 and 2002, respectively, and has recorded this amount as a
>   long-term liability in the accompanying balance sheets.

F - 15

---



|BreitBurn Energy Company LLC 
    and Subsidiaries 
    Notes to Consolidated Financial Statements
|--------------------------------------------------------------------------------------------------

8.

> The changes in asset retirement obligations from January 1, 2003 to
>   December 31, 2003 are as follows:

|Asset retirement obligations
      as of January 1, 2003   | $ | 650,288
|---------------------------------------------------------- | - | -------
|Reduction for wells sold                                   |   | (8,897)
|Accretion expense                                          |   | 67,373 
|                                                           |   |        
|Asset retirement obligations
      as of December 31, 2003 | $ | 708,764

The Company leases certain property and equipment under
  operating leases that may expire over the next five years. Generally,
  management expects that leases will be renewed or replaced by other leases in
  the normal course of business. Maximum payments for operating leases having
  initial or remaining noncancelable terms in excess of one year are as follows:

|Year Ending |   |        
|----------- | - | -------
|            |   |        
|2004        | $ | 412,466
|2005        |   | 265,689
|2006        |   | 7,604  
|2007        |   | 2,900  
|2008        |   | -      
|            |   |        
|            | $ | 688,659

Rent expense for the years ended December 31, 2003 and 2002 amounted to
  $416,660 and $402,859, respectively.

9.

> The Company had accrued interest payable of $49,161 and
>   $44,151 at December 31, 2003 and 2002, respectively, to a parent corporation
>   of a member, on their $1.5 million outstanding note payable.
>   The Company has interest bearing notes receivable due from
>   members of $500,000 at December 31, 2003 and 2002. Interest accrues utilizing
>   the Blended Annual Federal Rate and is payable annually. Accrued interest at
>   December 31, 2003 and 2002 was $7,600 and $14,733, respectively.
>   At December 31, 2003 and 2002, the Company had recorded
>   receivables from Seal Beach Gas Processing Venture ("SBGPV"), an affiliate
>   accounted for on the equity method in which the Company owns a 50% interest,
>   of $25,749 and $11,119, respectively. Payables to SBGPV were $0 and $8,270 at
>   December 31, 2003 and 2002, respectively.

F - 16

---



|BreitBurn Energy Company LLC 
    and Subsidiaries 
    Notes to Consolidated Financial Statements
|--------------------------------------------------------------------------------------------------

9.

> A member has a working interest in a portion of certain
>   leases and reimburses the Company for its portion of the lease operating
>   expenses and capital expenditures. At December 31, 2003 and 2002, the Company
>   had recorded receivables of $201,686 and $514,022, respectively, from the
>   member.
>   On May 5, 2003, the Company sold two oil and gas properties
>   to the Partnership for approx. $35 million, which resulted in a gain of
>   approx. $10 million for the Company. The Company retains a general partner
>   equity interest in the properties and continues to be the operator of both
>   properties through the Partnership. The Company earns a management fee of 4%
>   of operating income for providing this service to the Partnership.

10.         Retirement Plan

> The Company's defined contribution retirement plan, which
>   covers substantially all of its employees who have completed at least three
>   months of service, provides for the Company to make regular contributions
>   based on employee contributions as provided for in the plan agreement.
>   Employees fully vest in the Company's contributions after 5 years of service.
>   For the years ended December 31, 2003 and 2002, the matching contributions
>   were $81,574 and $115,275, respectively.

11.         Supplemental Cash Flow
Information

> The Company paid $2,752,617 and $3,742,795 for interest during the years
>   ended December 31, 2003 and 2002, respectively.

12.         Discontinued Operations

> During January 2002, the Company adopted a formal plan to
>   dispose of the Company's nonoperating interest in the Beta field located in
>   offshore California waters. The non-operating interest was accounted for as a
>   discontinued operation beginning with the 2002 consolidated financial
>   statements. To effect the disposal, the Company paid $5,000,000 in cash to the
>   operator and recognized $4,000,000 in deferred payments. The Company recorded
>   a book loss on the sale of this business of $6,608,840, including closing
>   costs from the transaction and operating losses of the discontinued business
>   from January 1 through April 1, 2002 (the disposal date). The Company is not
>   subject to federal income taxes as it has elected to be taxed as a
>   partnership.

F - 17

---



|BreitBurn Energy Company LLC 
    and Subsidiaries 
    Notes to Consolidated Financial Statements
|--------------------------------------------------------------------------------------------------

13.         Canadian GAAP
Reconciliation

> The Company prepares its consolidated financial statements
>   in accordance with accounting principles generally accepted in the United
>   States ("US GAAP"), which differ in certain respects from the principles that
>   the Company would have followed had its consolidated financial statements been
>   prepared in accordance with accounting principles generally accepted in Canada
>   ("Canadian GAAP"). The major measurement differences between US GAAP and
>   Canadian GAAP and their effects on the consolidated financial statements are
>   provided below.
>   The amounts in the consolidated income statement that differ significantly
>   from those reported under US GAAP are as follows:

|                                                             |   | 2003              |   | 2002       
|------------------------------------------------------------ | - | ----------------- | - | -----------
|                                                             |   | (In U.S. Dollars)
|Net income - US GAAP                                         | $ | 17,112,232        | $ | 4,782,053  
|Gain on change in fair value
      of derivative instruments |   |                   |   | (926,153)  
|Cumulative effect for
      accounting change for FAS 143    |   | (1,653,303)       |   | 328,000    
|Redeemable preferred stock
      accretion                   |   | (637,452)         |   | (637,452)  
|Redeemable preferred cash
      dividend                     |   | (1,823,259)       |   | (3,646,519)
|Accrued preferred stock
      dividend                       |   | (2,222,883)       |   |            
|Net income (loss) - Canadian
      GAAP                      | $ | 10,775,335        | $ | (100,071)  

The amounts in the consolidated balance sheet that differ significantly
  from those reported under US GAAP are as follows:

|                            | 2003              |             | 2002       |            
|--------------------------- | ----------------- | ----------- | ---------- | -----------
|                            | Canadian          | U.S.        | Canadian   | U.S.       
|                            | GAAP              | GAAP        | GAAP       | GAAP       
|                            | (In U.S. Dollars)
|Current assets              |                   |             |            |            
|Hedge
      asset           | -                 | -           | -          | 5,586      
|                            |                   |             |            |            
|Other assets                |                   |             |            |            
|Hedge
      asset           | -                 | -           | -          | 26,227     
|                            |                   |             |            |            
|Current liabilities         |                   |             |            |            
|Hedge
      liability       | -                 | 6,180,066   | -          | 3,798,213  
|                            |                   |             |            |            
|Other liabilities           |                   |             |            |            
|Hedge
      liability       | -                 | 3,120,805   | -          | 879,586    
|Redeemable preferred shares | 37,784,991        | -           | 34,924,655 | -          
|                            |                   |             |            |            
|Equity                      |                   |             |            |            
|Redeemable preferred shares | -                 | 37,784,991  | -          | 34,924,655 
|Accumulated Other           |                   |             |            |            
|Comprehensive Loss          | -                 | (9,300,871) | -          | (4,645,986)

F - 18

---



|BreitBurn Energy Company LLC 
    and Subsidiaries 
    Notes to Consolidated Financial Statements
|--------------------------------------------------------------------------------------------------

13.        Canadian GAAP Reconciliation
(Continued)

> Hedge liability
>   Canadian GAAP does not require effective hedges to be marked to market and
>   charged to other comprehensive income.
>   Redeemable preferred shares
>   Canadian GAAP requires Redeemable preferred shares to be recorded as debt
>   Asset retirement obligation
>   Canadian Institute of Chartered Accounts ("CICA") handbook
>   section 3110, "Asset Retirement Obligations," 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. 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 prior periods not be restated while Canadian GAAP
>   requires the restatement of prior periods.
>   Redeemable shares
>   Under Canadian GAAP Redeemable preferred stock accretion, Redeemable
>   preferred cash dividend and Accrued preferred stock dividends are recorded as
>   expense.
>   Accumulated other comprehensive loss
>   U.S. GAAP requires the disclosure, as other comprehensive
>   income or loss, of changes in equity during the period from transactions and
>   other events from non-owner sources. Canadian GAAP does not require similar
>   disclosure.

F - 19

---





BreitBurn Energy Company LLC 
and Subsidiaries

Consolidated Financial Statements 
For the Three Month Periods Ended March 31, 2004 and 2003









F - 20

---



|BreitBurn Energy Company LLC                                                          |   |              |              |             |           
|------------------------------------------------------------------------------------- | - | ------------ | ------------ | ----------- | ----------
|and Subsidiaries                                                                      |   |              |              |             |           
|Consolidated Balance Sheets                                                           |   |              |              |             |           
|(Unaudited)                                                                           |   |              |              |             |           
|                                                                                      |   | March 31,    | December 31,
|                                                                                      |   | 2004         |              | 2003       
|Assets                                                                                |   |              |              |             |           
|Current assets                                                                        |   |              |              |             |           
|Cash and cash equivalents                                                             | $ |              | -            | $           | 714,570   
|Accounts receivable                                                                   |   |              |              |             |           
|Trade, net of allowance for doubtful accounts of $42,054 and $42,054                  |   |              |              |             |           
|as of March 31, 2004 and December 31, 2003, respectively                              |   | 5,486,788    |              | 5,012,823  
|Other receivable                                                                      |   | 474,180      |              | 634,082    
|Prepaid expenses                                                                      |   | 538,465      |              | 653,984    
|Deposits and other                                                                    |   | 176,028      |              | 166,030    
|                                                                                      |   |              |              |             |           
|Total current assets                                                                  |   | 6,675,461    |              | 7,181,489  
|                                                                                      |   |              |              |             |           
|Property, plant and equipment, net                                                    |   | 99,348,362   |              | 96,845,940 
|                                                                                      |   |              |              |             |           
|Other assets                                                                          |   |              |              |             |           
|Abandonment bonds                                                                     |   | 150,000      |              | 100,000    
|Debt issuance costs,
    net of accumulated amortization of $977,101 and $910,088     |   |              |              |             |           
|as of March 31, 2004 and December 31, 2003, respectively                              |   | 441,306      |              | 103,530    
|Investment in
    affiliates                                                          |   | 620,346      |              | 581,691    
|Notes receivable -
    related parties                                                |   | 500,000      |              | 500,000    
|Other long-term
    assets                                                            |   | 40,849       |              | 40,849     
|                                                                                      |   |              |              |             |           
|                                                                                      |   | 1,752,501    |              | 1,326,070  
|                                                                                      |   |              |              |             |           
|Total assets                                                                          | $ | 107,776,324  | $            | 105,353,499
|                                                                                      |   |              |              |             |           
|Liabilities and Members' Equity (Deficit)                                             |   |              |              |             |           
|Current liabilities                                                                   |   |              |              |             |           
|Accounts
    payable and accrued liabilities                                          | $ | 9,169,978    | $            | 7,793,309  
|Hedge
    liability                                                                   |   | 8,485,839    |              | 6,180,066  
|Derivative
    settlements payable                                                    |   | 1,069,174    |              | 862,653    
|Liability due
    to disposal of non-operating interest                               |   | 3,000,000    |              | 2,000,000  
|Senior
    subordinated debt due to member                                            |   | 1,500,000    |              | 1,500,000  
|Current
    portion of long-term debt                                                 |   | 37,600,000   |              | 37,400,000 
|Shares subject
    to mandatory redemption                                            |   | 38,688,083   |              | -          
|                                                                                      |   |              |              |             |           
|Total current liabilities                                                             |   | 99,513,074   |              | 55,736,028 
|                                                                                      |   |              |              |             |           
|Abandonment liability                                                                 |   | 724,512      |              | 708,764    
|Hedge liability                                                                       |   | 6,169,609    |              | 3,120,805  
|Liability due to disposal of non-operating
    interest                               |   |              | -            |             | 1,500,000 
|Other long-term liability                                                             |   | 1,750,672    |              | 1,130,000  
|                                                                                      |   |              |              |             |           
|Total liabilities                                                                     |   | 108,157,867  |              | 62,195,597 
|                                                                                      |   |              |              |             |           
|Commitments and contingencies (Note 8)                                                |   |              |              |             |           
|                                                                                      |   |              |              |             |           
|Redeemable preferred shares (no par;
    4,100,000 shares authorized;                 |   |              |              |             |           
|3,646,519
    shares issued and outstanding)                                          |   |              | -            |             | 37,784,991
|                                                                                      |   |              |              |             |           
|Members' equity: (Class A: no par; 12,169,318
    shares authorized, issued and       |   |              |              |             |           
|outstanding; Class
    B: no par; 959,625 shares authorized, 926,750 (March 31, 2004) |   |              |              |             |           
|and 918,750
    (December 31, 2003); shares issued and outstanding)                   |   | 14,273,905   |              | 14,673,782 
|Accumulated other comprehensive loss                                                  |   | (14,655,448) |              | (9,300,871)
|                                                                                      |   |              |              |             |           
|Total members' equity (deficit)                                                       |   | (381,543)    |              | 5,372,911  
|                                                                                      |   |              |              |             |           
|Total liabilities and members' equity (deficit)                                       | $ | 107,776,324  | $            | 105,353,499

F - 21

---



|BreitBurn Energy Company LLC                                            |   |                    |   |          
|----------------------------------------------------------------------- | - | ------------------ | - | ---------
|and Subsidiaries                                                        |   |                    |   |          
|Consolidated Statements of Operations                                   |   |                    |   |          
|(Unaudited)                                                             |   |                    |   |          
|                                                                        |   | Three Months Ended
|                                                                        |   | March 31,         
|                                                                        |   | 2004               |   | 2003     
|Revenues                                                                |   |                    |   |          
|Oil and gas sales, net of hedging loss of
    $2,749,131 and $2,958,090 |   |                    |   |          
|for the three months
    ended March 31, 2004 and 2003, respectively    | $ | 6,452,399          | $ | 9,309,767
|Gain on sale of assets                                                  |   | -                  |   | 900      
|Equity earnings in affiliate                                            |   | 65,684             |   | 57,661   
|Operating fees                                                          |   | 143,884            |   | 124,547  
|                                                                        |   |                    |   |          
|                                                                        |   | 6,661,967          |   | 9,492,875
|                                                                        |   |                    |   |          
|Operating costs and expenses                                            |   |                    |   |          
|Gas and NGL purchases                                                   |   | 26,683             |   | 27,660   
|Lease operating expenses                                                |   | 3,266,966          |   | 4,018,739
|Production and property taxes                                           |   | 283,505            |   | 378,424  
|Depletion, depreciation and amortization of
    proved oil and          |   |                    |   |          
|gas properties                                                          |   | 735,485            |   | 901,778  
|General and administrative expenses                                     |   | 995,394            |   | 812,649  
|                                                                        |   |                    |   |          
|                                                                        |   | 5,308,033          |   | 6,139,250
|                                                                        |   |                    |   |          
|Operating income                                                        |   | 1,353,934          |   | 3,353,625
|                                                                        |   |                    |   |          
|Other (income) expense                                                  |   |                    |   |          
|Interest expense                                                        |   | 641,024            |   | 890,648  
|Interest income                                                         |   | (3,651)            |   | (4,654)  
|Amortization of debt issuance costs                                     |   | 67,013             |   | 67,014   
|Depreciation of non-oil and gas assets                                  |   | 45,916             |   | 45,600   
|Other expense                                                           |   | 115,796            |   | 107,261  
|Other income                                                            |   | (15,386)           |   | (14,626) 
|                                                                        |   |                    |   |          
|                                                                        |   | 850,712            |   | 1,091,243
|                                                                        |   |                    |   |          
|Income before cumulative effect of accounting change                    |   | 503,222            |   | 2,262,382
|                                                                        |   |                    |   |          
|Cumulative effect of accounting change                                  |   | (903,099)          |   | 1,653,303
|                                                                        |   |                    |   |          
|Net income (loss)                                                       | $ | (399,877)          | $ | 3,915,685

F - 22

---



|BreitBurn Energy Company LLC                               |                    |            
|---------------------------------------------------------- | ------------------ | -----------
|and Subsidiaries                                           |                    |            
|Consolidated Statements of
    Comprehensive Income (Loss) |                   
|(Unaudited)                                                |                    |            
|                                                           |                    |            
|                                                           | Three Months Ended
|                                                           | March 31,         
|                                                           | 2004               | 2003       
|                                                           |                    |            
|Net income (loss)                                          | $ (399,877)        | $ 3,915,685
|                                                           |                    |            
|Change in fair value of derivative
    instruments         | (5,354,577)        | (435,683)  
|                                                           |                    |            
|Comprehensive income (loss)                                | $ (5,754,454)      | $ 3,480,002



F - 23

---

BreitBurn Energy Company LLC and Subsidiaries 
Consolidated Statements of Members' Equity (Deficit) 
(Unaudited)

|                                                   |            |             |               |           |               |            
|-------------------------------------------------- | ---------- | ----------- | ------------- | --------- | ------------- | -----------
|                                                   |            |             |               |           | Accumulated   |            
|                                                   |            |             |               |           | Other         |            
|                                                   | Class A.   | Class B.    | Comprehensive |          
|                                                   | Shares     | Amount      | Shares        | Amount    | Loss          | Total      
|                                                   |            |             |               |           |               |            
|Balance at December 31, 2003                       | 12,169,318 | $14,029,504 | 918,750       | $ 644,278 | $ (9,300,871) | $ 5,372,911
|                                                   |            |             |               |           |               |            
|                                                   |            |             |               |           |               |            
|Issuance of Class B common shares                  |            |             | 8,000         |           |               |            
|Net income                                         |            | (372,589)   |               | (27,288)  |               | (399,877)  
|Change in fair value of derivative
    instruments |            |             |               |           | (5,354,577)   | (5,354,577)
|                                                   |            |             |               |           |               |            
|Balance at March 31, 2004                          | 12,169,318 | $13,656,915 | 926,750       | $ 616,990 | $(14,655,448) | $ (381,543)

---

BreitBurn Energy Company LLC and Subsidiaries 
Consolidated Statements of Cash Flows 
(Unaudited)

|                                                                       |   | Three
    Months Ended
|---------------------------------------------------------------------- | - | ----------------------
|                                                                       |   | March
    31,         
|                                                                       |   | 2004                  
|Cash flows from operating
    activities                               |   |                       
|Net income (loss)                                                      | $ | (399,877)             
|Adjustments to reconcile net
    income (loss) to net cash provided by |   |                       
|operating
    activities                                               |   |                       
|Cumulative
    effect of accounting change                             |   | 903,099               
|Depletion,
    depreciation and amortization                           |   | 781,401               
|Amortization
    of debt issuance costs                                |   | 67,013                
|Equity
    earnings in affiliate                                       |   | (65,684)              
|Distributions
    received from affiliates                             |   | -                     
|Gain on sales
    of assets                                            |   | -                     
|Changes in
    working capital                                         |   |                       
|Increase in accounts receivable                                        |   | (314,065)             
|(Increase) decrease in prepaid expenses, deposits and other            |   | 82,554                
|Increase in accounts payable and accrued liabilities                   |   | 1,703,854             
|                                                                       |   |                       
|Net cash provided by operating activities                              |   | 2,758,295             
|                                                                       |   |                       
|Cash flows from investing
    activities                               |   |                       
|Expenditures for oil and gas
    properties                            |   | (3,259,222)           
|Expenditures for land                                                  |   | -                     
|Proceeds from sales of assets                                          |   | -                     
|Additions to non-oil and gas
    assets                                |   | (8,853)               
|                                                                       |   |                       
|Net cash used in investing activities                                  |   | (3,268,075)           
|                                                                       |   |                       
|Cash flows from financing
    activities                               |   |                       
|Proceeds from long-term debt                                           |   | 19,600,000            
|Payments on long-term debt                                             |   | (19,400,000)          
|Debt issuance costs                                                    |   | (404,790)             
|                                                                       |   |                       
|Net cash used in financing activities                                  |   | (204,790)             
|                                                                       |   |                       
|Net decrease in cash and cash
    equivalents                          |   | (714,570)             
|                                                                       |   |                       
|Cash and cash equivalents                                              |   |                       
|Beginning of year                                                      |   | 714,570               
|                                                                       |   |                       
|End of period                                                          | $ | 0                     
|                                                                       |   |                       

F-25

---

BreitBurn Energy Company LLCand SubsidiariesNotes to Consolidated Financial Statements

1. General

> Organization and Description of Operations
>   BreitBurn Energy Company LLC (the "Company"), organized
>   under the State of California Beverly-Killea Limited Liability Company Act,
>   was formed on March 5, 1997, and will expire on or before March 5, 2027. The
>   Company is engaged in the acquisition, exploration, development and production
>   of oil and gas properties, in the States of California, Texas and Wyoming. For
>   the periods ended March 31, 2004 and 2003, 97% and 97% of the Company's
>   revenues were derived from its California properties, respectively.
>   On March 26, 2003, the Company formed BreitBurn Energy
>   Partners I, L.P. (the "Partnership"), a Texas limited partnership, which will
>   expire on or before April 1, 2023. Operations of the Partnership began on May
>   5, 2003. BEP (GP) I, LP, a wholly owned subsidiary of the Company, is a 1%
>   general partner in the Partnership. TIFD III-X, LLC, a subsidiary of GE
>   Capital, is the limited partner with a 99% partnership interest. The
>   Partnership is engaged in the acquisition, exploration, development and
>   production of oil and gas properties. For the three month period ended March
>   31, 2004, the sale of these assets resulted in reductions of 29%, 26% and 18%
>   in revenues, production volumes and lease operating expenses, respectively,
>   when compared to levels prior to the transaction.
>   Basis of Presentation
>   The accompanying condensed consolidated interim financial statements are
>   unaudited and have been prepared in accordance with generally accepted
>   accounting principles in the United States. Accordingly, they do not include
>   all of the information and footnotes required by generally accepted accounting
>   principles for complete financial statements. The year-end balance sheet data
>   was derived from audited financial statements, but does not include all
>   disclosures required by generally accepted accounting principles. The
>   unaudited consolidated financial statements should be read in conjunction with
>   the audited consolidated financial statements and footnotes for the year ended
>   December 31, 2003. In the opinion of management, all adjustments and normal
>   recurring accruals considered necessary for a fair statement of the results
>   for the interim periods have been included. The interim results reflected in
>   the unaudited consolidated financial statements are not necessarily indicative
>   of expected results for the full year.

1. Significant Accounting Policies

> Principles of Consolidation
>   The consolidated financial statements include the accounts
>   of the Company and its wholly owned subsidiaries. Investments in affiliated
>   companies with a 20% or greater ownership interest, and in which the Company
>   does not have control, are accounted for on the equity basis. Investments in
>   affiliated companies with less than a 20% ownership interest, and in which the
>   Company does not have control, are accounted for at cost. The effects of all
>   intercompany transactions have been eliminated.

F-26

---



|BreitBurn Energy Company LLC              
|------------------------------------------
|and Subsidiaries                          
|Notes to Consolidated Financial Statements

1. Significant
  Accounting Policies (Continued)

> Revenue Recognition
>   Oil and gas revenue is recognized when title passes to the customer.
>   Cash and Cash Equivalents
>   Cash and cash equivalents include short-term investments with an original
>   maturity of three months or less.
>   Oil and Gas Properties
>   The Company follows the successful efforts method of
>   accounting. Lease acquisition and development costs (tangible and intangible)
>   incurred, including internal acquisition costs, relating to proved oil and gas
>   properties are capitalized. Delay and surface rentals are charged to expense
>   as incurred. Dry hole costs incurred on exploratory wells are expensed. Dry
>   hole costs associated with developing proved fields are capitalized.
>   Geological and geophysical costs related to exploratory operations are
>   expensed as incurred.
>   Upon sale or retirement of proved properties, the cost
>   thereof and the accumulated depletion, depreciation and amortization are
>   removed from the accounts and any gain or loss is recognized in the statements
>   of operations and comprehensive income. Maintenance and repairs are charged to
>   operating expenses. Depletion, depreciation and amortization of proved oil and
>   gas properties, net of any anticipated proceeds from equipment salvage and
>   sale of surface rights, as well as the estimated cost of future abandonment
>   and restoration of well sites and associated facilities, are computed on a
>   property-by-property basis and recognized using the units-of-production
>   method.
>   The Company's policy is to capitalize interest on significant drilling
>   projects based on its incremental borrowing rate.
>   Buildings and Non-Oil and Gas Assets
>   Buildings and non-oil and gas assets are recorded at cost and depreciated
>   using the straight-line method over their estimated useful lives, which range
>   from 3 to 30 years.
>   Debt Issuance Costs
>   The costs incurred to obtain financing have been
>   capitalized. Debt issuance costs are amortized using the straight-line method
>   over the life of the debt. During the first quarter of 2004, the Company
>   incurred $404,790 in debt issuance costs to secure a $10,000,000 subordinated
>   line of credit with Wells Fargo Energy Capital, Inc. for drilling activities.
>   Concentration of Credit Risk
>   The Company maintains its cash accounts primarily with a
>   single bank and invests cash in money market accounts, which the Company
>   believes to have minimal risk. As operator of jointly owned oil and gas
>   properties, the Company sells oil and gas production to U.S. oil and gas
>   purchasers, and pays vendors on behalf of joint owners for oil and gas
>   services. Both purchasers and joint owners are located primarily in the
>   Western United States. The risk of nonpayment by the purchasers or joint
>   owners is considered minimal and has been considered in the Company's
>   allowance for doubtful accounts.

F-27

---



|BreitBurn Energy Company LLC              
|------------------------------------------
|and Subsidiaries                          
|Notes to Consolidated Financial Statements

1. Significant
  Accounting Policies (Continued)

> At March 31, 2004 and 2003, 75% and 75%, respectively, of the Company's
>   trade receivables were due from a large domestic refiner of crude oil.
>   Environmental Concerns
>   The Company is continually taking actions it believes
>   necessary in its operations to ensure conformity with applicable federal,
>   state and local environmental regulations. As of December 31, 2003, the
>   Company has not been fined or cited for any environmental violations, which
>   would have a material adverse effect upon capital expenditures or operating
>   results of the Company.
>   Stock Compensation
>   The employee stock ownership plan is accounted for under
>   the provisions of APB Opinion No. 25, "Accounting for Stock Issued to
>   Employees." APB No. 25 requires the use of the intrinsic value method, which
>   measures compensation cost as the excess, if any, of the fair value of the
>   stock at grant over the amount an employee must pay to acquire the stock. SFAS
>   No. 123, "Accounting for Stock-Based Compensation," established accounting and
>   disclosure requirements using a fair-value based method of accounting for
>   stock-based employee compensation plans. The Company has elected to retain its
>   current method of accounting as described above and has adopted the disclosure
>   requirements of SFAS No. 123.
>   Impairment of Assets
>   Oil and gas properties are regularly assessed for possible
>   impairment, generally on a field-by-field basis where applicable, using the
>   estimated undiscounted future cash flows of each field. Impairment losses are
>   recognized when the estimated undiscounted future cash flows are less than the
>   current net book values of the properties in a field.
>   Impairment charges are also made for other long-lived assets when it is
>   determined that the carrying values of the assets may not be recoverable.
>   The Company did not record an impairment charge in 2004 or 2003.
>   Adoption of SFAS No. 143
>   In June 2001, the Financial Accounting Standards Board ("FASB")
>   issued SFAS No. 143, "Accounting for Asset Retirement Obligations." This
>   statement requires that the Company recognize liabilities related to the legal
>   obligations associated with the retirement of its tangible long-lived assets
>   at fair values in the periods in which the obligations are incurred (typically
>   when the assets are installed). These obligations include the plugging and
>   abandonment of oil and gas wells and facilities and the closure and site
>   restoration of certain facilities.
>   Prior to January 1, 2003, the Company was required, under
>   SFAS No. 19, "Financial Accounting and Reporting by Oil and Gas Producing
>   Companies," to accrue its abandonment and restoration costs ratably over the
>   productive lives of its assets. The Company previously used the
>   units-of-production method to accrue these costs. SFAS No. 19 resulted in
>   higher costs being accrued early in the fields' lives when production was at
>   its highest levels and abandonment and restoration costs accruals were matched
>   with the revenues as oil and gas were produced.

F-28

---



|BreitBurn Energy Company LLC              
|------------------------------------------
|and Subsidiaries                          
|Notes to Consolidated Financial Statements

1. Significant Accounting Policies (Continued)

> Under SFAS No. 143, when the liabilities for asset
>   retirement obligations are initially recorded at fair values, capital costs of
>   the related assets will be increased by equal corresponding amounts. Over
>   time, changes in the present value of the liabilities will be accreted and
>   expensed and the capitalized asset costs will be depreciated over the useful
>   lives of the corresponding assets. Because SFAS No. 143 requires the use of
>   interest accretion for revaluing asset retirement obligation liabilities as a
>   result of the passage of time, associated accretion costs will be higher near
>   the end of the fields' lives when oil and gas production and related revenues
>   are at their lowest levels.
>   In accordance with the provisions of SFAS No. 143 the
>   company recorded a cumulative-effect adjustment of $1,653,303 as the
>   cumulative effect of an accounting change related to the adoption of SFAS No.
>   143. Accretion expense for the three months ended March 31, 2004 and 2003 was
>   $15,748 and $16,392, respectively.
>   Adoption of FAS 150
>   Effective January 1, 2004, the Company adopted SFAS No.
>   150, "Accounting for Certain Instruments with Characteristics of Both
>   Liabilities and Equity," which establishes standards for how an issuer
>   classifies and measures certain financial instruments with characteristics of
>   both liabilities and equity. SFAS No. 150 requires that the Company classify a
>   financial instrument that is within its scope, which may have previously been
>   reported as equity, as a liability or an asset in some circumstances. The
>   adoption of the Statement resulted in the reclassification of the Company's
>   mandatorily redeemable preferred securities from equity to a liability and a
>   transition loss of $903,099. As required by SFAS No. 150, prior year balances
>   have not been reclassified.
>   Derivative Instruments
>   SFAS No. 133, "Accounting for Derivative Instruments and
>   Hedging Activities", as amended establishes accounting and reporting standards
>   for derivative instruments, including certain derivative instruments embedded
>   in other contracts, and hedging activities. It requires the recognition of all
>   derivative instruments as assets or liabilities in the Company's balance sheet
>   and measurement of those instruments at fair value. The accounting treatment
>   of changes in fair value is dependent upon whether or not a derivative
>   instrument is designated as a hedge and if so, the type of hedge. For
>   derivatives designated as cash flow hedges, changes in fair value are
>   recognized in other comprehensive income; to the extent the hedge is
>   effective, until the hedged item is recognized in earnings. Hedge
>   effectiveness is measured based on the relative changes in fair value between
>   the derivative contract and the hedged item over time. Any change in fair
>   value resulting from ineffectiveness, as defined by SFAS No.133, is recognized
>   immediately in earnings.
>   Income Taxes
>   The Company is not subject to income tax as it has elected
>   to be taxed as a partnership for income tax reporting purposes and the income
>   or loss of the Company is included in the income tax returns of the individual
>   members.

F-29

---



|BreitBurn Energy Company LLC              
|------------------------------------------
|and Subsidiaries                          
|Notes to Consolidated Financial Statements

1. Significant
  Accounting Policies (Continued)

> Use of Estimates
>   The preparation of financial statements in conformity with
>   accounting principles generally accepted in the United States of America
>   requires management to make estimates and assumptions that affect the reported
>   amounts of assets and liabilities and disclosure of contingent assets and
>   liabilities at the date of the financial statements and the reported amounts
>   of revenues and expenses during the reporting period. Actual results could
>   differ from those estimates.
>   The financial statements are based on a number of
>   significant estimates including oil and gas reserve quantities, which are the
>   basis for the calculation of depletion, depreciation, amortization and
>   impairment of oil and gas properties.
>   Management's Plan
>   The accompanying consolidated financial statements have
>   been prepared on a going concern basis, which contemplates the realization of
>   assets and the satisfaction of liabilities in the normal course of business.
>   The Company has debt obligations with scheduled maturities during 2004
>   totaling $38.9 million. Additionally, as more fully described in Note 7, the
>   Company has redeemable preferred stock subject to mandatory redemption on
>   December 31, 2004 totaling $38.7 million. These matters raise substantial
>   doubt about the Company's ability to continue as a going concern. The
>   consolidated financial statements do not include any adjustments that might
>   result from the outcome of these uncertainties.
>   As more fully described in Note 12, on June 15, 2004, the
>   Company entered into an Agreement and Plan of Merger with Provident Energy
>   Trust. As part of this agreement, all outstanding debt and preferred shares
>   were repaid.

1. Fair Value of Financial Instruments

> The carrying value of cash, accounts receivable, accounts
>   payable and accrued liabilities are carried at cost, which approximates their
>   fair market value because of the short-term maturity of these instruments. The
>   fair value of the Company's long-term debt approximates the carrying value due
>   to the market-based nature of the line of credit.
>   The Company periodically hedges a portion of its oil and
>   gas production through futures and swap agreements. The purpose of the hedge
>   is to stabilize its exposure to commodity price risk in the volatile
>   environment of oil and gas prices. All of the Company's swap agreements in
>   place at March 31, 2004 and 2003 are designated as cash flow hedges. At March
>   31, 2004 and 2003 cash flow hedges consisted of swap contracts and put options
>   to hedge between 500 and 4,000 barrels of oil production per day from January
>   1, 2003 through December 31, 2006. These contracts have a swap price range of
>   $23.03 to $25.07 per barrel. The net fair values of these contracts at March
>   31, 2004 and 2003 are losses of approximately $13,461,000 and $3,518,661,
>   respectively.

F-30

---



|BreitBurn Energy Company LLC              
|------------------------------------------
|and Subsidiaries                          
|Notes to Consolidated Financial Statements

1. Fair Value
  of Financial Instruments (Continued)

> The Company uses interest-rate swaps to convert a portion
>   of its variable-rate debt to fixed rates. At March 31, 2004 and 2003, the
>   notional principal amount of the Company's interest-rate swaps ranged from
>   $35,000,000 to $45,000,000, respectively. The net gain or loss resulting from
>   the interest-rate swap was not significant to the Company and is recorded in
>   interest expense.

1. Property, Plant and Equipment

> Property, plant and equipment at March 31, 2004 and December 31, 2003 was
>   as follows:
>   March 31,
>       December 31,2003
>       2003Proved oil and gas properties,
>       successful effortsmethod
>       $ 113,906,597
>       $ 110,647,375Land
>       1,990,384
>       1,990,384Buildings
>       274,483
>       274,483Non-oil and gas assets
>       1,166,346
>       1,157,493117,337,810
>       114,069,735Less accumulated depletion,
>       depreciation andamortization
>       (17,989,448)
>       (17,223,795)Property, plant and equipment,
>       net
>       $ 99,348,362
>       $ 96,845,940There was no interest capitalized to oil and gas properties for the three
>   month periods ended March 31, 2004 and 2003, respectively.

1. Notes Payable

> Notes payable consist of the following at March 31, 2004 and December 31
>   2003:
>   Type of
>       Interest
>       Interest
>       March 31,
>       December 31,Note
>       Rate
>       Payment
>       
>       2004
>       
>       2003
>       MaturitySenior CreditAgreement
>       Various
>       Quarterly
>       $
>       2,600,000
>       $
>       6,400,000
>       May 5, 2004Senior CreditAgreement
>       Various
>       Monthly
>       
>       31,000,000
>       
>       31,000,000
>       May 5, 2004Subordinated CreditAgreement
>       Various
>       Monthly
>       
>       4,000,000
>       
>       -
>       June 1, 2004Promissory Note
>       Various
>       Quarterly
>       
>       1,500,000
>       
>       1,500,000
>       March 25, 2004$
>       39,100,000
>       $
>       38,900,000

F-31

---



|BreitBurn Energy Company LLC              
|------------------------------------------
|and Subsidiaries                          
|Notes to Consolidated Financial Statements

1. Notes Payable (Continued)

> The Company has a senior Credit Agreement (the "Agreement")
>   with Wells Fargo Bank (Texas), N.A., Bank of Scotland and U.S. Bank National
>   Association. Funds advanced under the Agreement are collateralized by the
>   Company's oil and gas producing properties and bear interest at either an
>   adjusted London Interbank Offered Rate ("LIBOR") plus 1.25% to 2% or Wells
>   Fargo Bank's base rate plus .25% to 1.00% (3.1% and 5.0%, respectively, at
>   December 31, 2003). The applicable basis point increase over the adjusted
>   LIBOR or the Wells Fargo Bank's base rate increases as the Company's
>   borrowings under the Agreement approach the available borrowing base.
>   The initial authorized borrowing base was established at
>   $50 million. The maximum loan amount under the Agreement is $150 million. The
>   borrowing base at December 31, 2003 under the Agreement was $40 million.
>   Outstanding borrowings subject to the adjusted LIBOR rate and base rate
>   borrowing were $31.0 million and $6.4 million, respectively, at December 31,
>   2003. In accordance with the Agreement, the entire amount outstanding at
>   December 31, 2003 is classified as short-term. The Agreement requires, among
>   other things, that the Company maintain at least a 1 to 1 current ratio and a
>   minimum adjusted cash flow to interest ratio of 1.25 to 1 as of December 31,
>   2003, all as defined in the Agreement.
>   The Company has a 10%, $1.5 million promissory note dated
>   March 25, 1997 and maturing on March 25, 2004 (the "Promissory Note") due to
>   Energy Company of America ("ECA"). The borrowing rate until maturity is 10%,
>   adjusted for the wellhead oil price received by the Company, which differs
>   from a set price of $20.79 per barrel (13.47% at December 31, 2003). The
>   promissory note was repaid in April 2004.
>   During 2004, the Company entered into a credit agreement
>   subordinate to the Senior Credit Agreement (the "Subordinated Agreement") with
>   Wells Fargo Energy Capital. Funds advanced under the Subordinated Agreement
>   are collateralized by the Company's oil and gas producing properties and bear
>   interest at Wells Fargo Bank's base rate plus 8.00% (12.0% at March 31, 2004).

F-32

---



|BreitBurn Energy Company LLC              
|------------------------------------------
|and Subsidiaries                          
|Notes to Consolidated Financial Statements

1. Notes Payable (Continued)

> The initial authorized borrowing base was established at $4
>   million. The maximum loan amount under the Subordinated Agreement is $10
>   million. In accordance with the Subordinated Agreement, the entire amount
>   outstanding at March 31, 2004 is classified as short-term. The Subordinated
>   Agreement requires, among other things, that the Company maintain at least a 1
>   to 1 current ratio and a minimum adjusted cash flow to interest ratio of 1.25
>   to 1 as of March 31, 2004, all as defined in the Agreement.
>   The terms of the Senior Credit Agreement and the Subordinated Agreement
>   were modified to extend the maturity dates to August 1, 2004 and September 1,
>   2004 respectively.

1. Members' Equity

> Members' equity at March 31, 2004 consists of 12,169,318
>   Class A common shares and 926,750 Class B common shares or units of membership
>   interest, as defined in California Corporations Code section 17001(z). An
>   individual capital account is maintained for each member and consists of that
>   member's capital contribution plus that member's share of profits and losses,
>   less any distributions, in accordance with applicable provisions of Internal
>   Revenue Code and Regulations. The profits and losses of the Company and all
>   items of income, gain or loss are allocated to a member in accordance with
>   that member's percentage interest calculated by the number of shares that
>   member holds in relation to the total number of shares issued.
>   Pursuant to the Company's operating agreement, the Company issued 334,698
>   Class A common shares on June 3, 2003 to EnCap. No consideration was received
>   due to this issue.
>   In 1997, the Board of Directors of the Company approved an
>   Employee Stock Ownership Plan (the "Plan") that covers key employees and board
>   members. The purpose of the plan is to provide an incentive to expand and
>   improve the profits and prosperity of the Company, and to assist the Company
>   in attracting and retaining key personnel through the grant of shares of the
>   Company's common stock. The Board of Directors of the Company has authorized 1
>   million Class B common shares for the Plan. The Class B common shares have no
>   voting rights. The stock issued under the Plan represents a profits interest
>   only, as defined in Revenue Procedure 93-27, 1993-2 C.B. 343 (1993), and is
>   granted without payment of any cash consideration. The Plan is effective for
>   ten years and termination of the Plan will not affect any stock previously
>   granted. The Company may repurchase the stock granted to such participant at a
>   purchase price and under terms defined in the Plan agreement. At March 31,
>   2004, the Company had 926,750 Class B common shares issued and outstanding
>   under the Plan. No compensation expense has been recognized for the Plan in
>   2004 or 2003.

F-33

---



|BreitBurn Energy Company LLC              
|------------------------------------------
|and Subsidiaries                          
|Notes to Consolidated Financial Statements

1. Redeemable
  Preferred Stock

> In 1998, the Company issued 167,349 Class A common shares
>   and 3,000,000 preferred shares for $29,150,000. The preferred shares do not
>   have any voting rights. The preferred shareholders are entitled to receive
>   distributions from the Company at the annual rate of 10% of the redemption
>   amount of $30,000,000 plus any dividends previously paid in-kind.
>   Distributions on the preferred shares are payable semi-annually on December 3
>   and June 3 of each year commencing on December 3, 1998. The first four
>   dividends were paid in-kind at the option of the Company. Distributions are
>   cumulative and accrue whether or not declared and whether or not there will be
>   funds legally available for the payment thereof. For the three month periods
>   ended March 31, 2004 and 2003, the Company paid no cash dividends. The Company
>   had a dividend due in December 2003 that the Company contractually modified to
>   come due March 31, 2004 in the form of an in-kind dividend payment. For the
>   period ended March 31, 2004, the Company issued 192,430 shares to satisfy the
>   in-kind dividend payment.
>   The Company has the option to redeem the preferred shares
>   at any time, and shares are subject to mandatory redemption on December 31,
>   2004, at a price per share equal to the redemption amount as defined by the
>   agreement.
>   The dividend rate subsequent to March 31, 2004 was revised to 15% per
>   annum. The dividend due on June 3, 2004 was contractually modified to be paid
>   in-kind at the option of the Company.
>   224,472 shares were issued by the Company on June 3, 2004 to satisfy the
>   dividend payment in-kind.

1. Commitments and Contingencies

> The Company has surety bonds to provide $4,858,280 of
>   coverage to OXY in connection with a purchase agreement entered into by
>   Westside in 1993 for the purchase of oil and gas producing properties.
>   The Company has accrued an abandonment liability related to
>   the abandonment of certain oil and gas properties of $724,512 and $708,764 at
>   March 31, 2004 and December 31, 2003, respectively, and has recorded this
>   amount as a long-term liability in the accompanying balance sheets.
>   The changes in asset retirement obligations from January 1, 2004 to March
>   31, 2004 are as follows:
>   Asset retirement obligations as of December
>       31, 2003
>       $
>       708,764Reduction for wells sold
>       
>       -Accretion expense
>       
>       15,748Asset retirement obligations as of March
>       31, 2004
>       $
>       724,512

F-34

---



|BreitBurn Energy Company LLC              
|------------------------------------------
|and Subsidiaries                          
|Notes to Consolidated Financial Statements

1. Commitments
  and Contingencies (Continued)

> The Company leases certain property and equipment under
>   operating leases that may expire over the next five years. Generally,
>   management expects that leases will be renewed or replaced by other leases in
>   the normal course of business. Maximum payments for operating leases having
>   initial or remaining noncancelable terms in excess of one year are as follows:
>   Year Ending2004
>       $
>       305,8832005
>       
>       265,6892006
>       
>       7,6042007
>       
>       2,9002008
>       
>       -$
>       582,076Rent expense for the three month periods ended March 31, 2004 and 2003
>   amounted to $83,525 and $83,312, respectively.

1. Related-Party Transactions

> The Company had accrued interest payable of $56,278 and
>   $49,161 at March 31, 2004 and December 31, 2003, respectively, to a parent
>   corporation of a member, on their $1.5 million outstanding promissory note
>   payable.
>   The Company has interest bearing notes receivable due from
>   members of $500,000 at March 31, 2004 and December 31, 2003. Interest accrues
>   utilizing the Blended Annual Federal Rate and is payable annually. Accrued
>   interest at March 31, 2004 and December 31, 2003 was $11,400 and $7,600,
>   respectively.
>   At March 31, 2004 and December 31, 2003, the Company had
>   recorded receivables from Seal Beach Gas Processing Venture ("SBGPV"), an
>   affiliate accounted for on the equity method in which the Company owns a 50%
>   interest, of $26,705 and $25,749, respectively. Payables to SBGPV were $6,616
>   and $0 at March 31, 2004 and December 31, 2003, respectively.
>   A member has a working interest in a portion of certain
>   leases and reimburses the Company for its portion of the lease operating
>   expenses and capital expenditures. At March 31, 2004 and December 31, 2003,
>   the Company had recorded receivables of $87,139 and $201,686, respectively,
>   from the member.
>   On May 5, 2003, the Company sold two oil and gas properties
>   to the Partnership for approx. $35 million, which resulted in a gain of
>   approx. $10 million for the Company. The Company retains a general partner
>   equity interest in the properties and continues to be the operator of both
>   properties through the Partnership. The Company earns a management fee of 4%
>   of operating income for providing this service to the Partnership.

F-35

---



|BreitBurn Energy Company LLC              
|------------------------------------------
|and Subsidiaries                          
|Notes to Consolidated Financial Statements

1. Retirement Plan

> The Company's defined contribution retirement plan, which
>   covers substantially all of its employees who have completed at least three
>   months of service, provides for the Company to make regular contributions
>   based on employee contributions as provided for in the plan agreement.
>   Employees fully vest in the Company's contributions after 5 years of service.
>   For the three month periods ended March 31, 2004 and 2003, the matching
>   contributions were $28,515 and $26,590, respectively.

1. Supplemental Cash Flow Information

> The Company paid $641,023 and $890,648 for interest during the three month
>   periods ended March 31, 2004 and 2003, respectively.

1. Subsequent Events

> On June 15, 2004, BreitBurn Energy Company LLC (the
>   "Company"), Provident Energy Trust and three of its subsidiaries entered into
>   an Agreement and Plan of Merger to acquire the Company via a merger of an
>   indirect, wholly-owned subsidiary of Provident merged with and into the
>   Company. As a result of the merger, all outstanding common and preferred
>   shares of the Company were converted into the right to receive cash
>   consideration and, in the case of shares held by BreitBurn Energy Corporation,
>   a combination of cash and continuing membership interests in the Company. The
>   merger agreement provides that, following the merger, the Company will convert
>   into a Delaware limited partnership with the same ownership structure as the
>   Company immediately following the merger.

F-36

---



|BreitBurn Energy Company LLC              
|------------------------------------------
|and Subsidiaries                          
|Notes to Consolidated Financial Statements

1. Canadian GAAP Reconciliation

> The Company prepares its consolidated financial statements
>   in accordance with accounting principles generally accepted in the United
>   States ("US GAAP"), which differ in certain respects from the principles that
>   the Company would have followed had its consolidated financial statements been
>   prepared in accordance with accounting principles generally accepted in Canada
>   ("Canadian GAAP"). The major measurement differences between US GAAP and
>   Canadian GAAP and their effects on the consolidated financial statements are
>   provided below.
>   The amounts in the consolidated income statement that differ significantly
>   from those reported under US GAAP are as follows:
>   Three months ended
>       Three months endedMarch 31, 2004
>       
>       March 31, 2003Net income (loss) - US GAAP
>       $
>       (399,877)
>       $
>       3,915,685Cumulative effect for
>       accounting change
>       
>       -
>       
>       (1,653,303)Redeemable preferred stock
>       accretion
>       
>       -
>       
>       (159,363)Redeemable preferred cash
>       dividend
>       
>       -
>       
>       (455,815)Accrued preferred stock
>       dividend
>       
>       -
>       
>       (555,721)Net income (loss) - Canadian
>       GAAP
>       $
>       (399,877)
>       $
>       1,091,484The amounts in the consolidated balance sheet that differ significantly
>   from those reported under US GAAP are as follows:
>   March 31, 2004
>       December 31, 2003Canadian
>       U.S.
>       Canadian
>       U.S.GAAP
>       GAAP
>       GAAP
>       GAAPCurrent liabilitiesHedge
>       liability
>       -
>       8,485,839
>       -
>       6,180,066Other liabilitiesHedge
>       liability
>       -
>       6,169,609
>       -
>       3,120,805Redeemable
>       preferred shares
>       -
>       -
>       37,784,991
>       -EquityRedeemable
>       preferred shares
>       -
>       -
>       -
>       37,784,991Accumulated
>       othercomprehensive loss
>       -
>       (14,655,448)
>       -
>       (9,300,871)

F-37

---



|BreitBurn Energy Company LLC              
|------------------------------------------
|and Subsidiaries                          
|Notes to Consolidated Financial Statements

1. Canadian GAAP Reconciliation (Continued)

> Hedge liability
>   Canadian GAAP does not require effective hedges to be marked to market and
>   charged to other comprehensive income.
>   Redeemable preferred shares
>   Canadian GAAP requires Redeemable preferred shares to be recorded as debt.
>   This is required for U.S. GAAP effective January 1, 2004.
>   Asset retirement obligation
>   Canadian Institute of Chartered Accounts ("CICA") handbook
>   section 3110, "Asset Retirement Obligations," 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. 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 prior periods not be restated while Canadian GAAP
>   requires the restatement of prior periods.
>   Redeemable shares
>   Under Canadian GAAP Redeemable preferred stock accretion, Redeemable
>   preferred cash dividend and Accrued preferred stock dividends are recorded as
>   expense.
>   Accumulated other comprehensive loss
>   U.S. GAAP requires the disclosure, as other comprehensive
>   income or loss, of changes in equity during the period from transactions and
>   other events from non-owner sources. Canadian GAAP does not require similar
>   disclosure.

F-38

---

Management's discussion and analysisThe following analysis provides a detailed
explanation of Provident's operating results for the quarter and year ended
December 31, 2004 compared to the year ended December 31, 2003 and should be
read in conjunction with the consolidated financial statements of Provident.
This analysis has been prepared using information available up to March 9, 2005.
This disclosure contains certain
forward-looking estimates that involve substantial known and unknown risks and
uncertainties, certain of which are beyond Provident's control. These include
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 if
any of them do so, what benefits, including the amounts of proceeds, Provident
will derive there from. All amounts are reported in Canadian dollars, unless
otherwise stated.
Provident Energy Trust has diversified
investments in certain segments of the energy value chain. Provident currently
operates in three key business segments: Canadian crude oil and natural gas
production and exploitation ("COGP"), United States crude oil and natural gas
production and exploitation, ("USOGP") and midstream services and marketing
("Midstream"). Provident's "COGP" business produces crude oil and natural gas
from five core areas in the western Canadian sedimentary basin. USOGP produces
crude oil and natural gas in the Los Angeles and Santa Maria basins in the
U.S.A. The Midstream business unit processes, markets, transports and offers
storage of natural gas liquids 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 COGP business unit, the USOGP business unit and the Midstream business unit.
The reporting focuses on the financial and operating measurements management
uses in making business decisions and evaluating performance.

- 1 -

---



|Consolidated
    financial highlights               |   |                            |            |                         |     |   |           |            |         |     
|--------------------------------------------------- | - | -------------------------- | ---------- | ----------------------- | --- | - | --------- | ---------- | ------- | ----
|(000s except per unit
    amounts)                  |   |                            |            |                         |     |   |           |            |         |     
|                                                    |   |                            |            |                         |     |   |           |            |         |     
|                                                    |   | Quarter ended December 31, |            | Year ended December 31,
|                                                    |   | 2004                       |            | 2003                    | (%) |   | 2004      |            | 2003    | (%) 
|                                                    |   |                            | (Restated) | Change                  |     |   |           | (Restated) | Change 
|                                                    |   |                            |            |                         |     |   |           |            |         |     
|Revenue                                             | $ | 369,435                    | $          | 214,477                 | (1) | $ | 1,109,857 | $          | 406,329 | 173 
|                                                    |   |                            |            |                         |     |   |           |            |         |     
|Cash flow from COGP
    operations (1)              | $ | 30,273                     | $          | 21,620                  | 40  | $ | 121,144   | $          | 119,561 | 1   
|Cash flow from USOGP
    operations(1)              | $ | 11,525                     | $          | -                       | -   | $ | 21,458    | $          | -       | -   
|Cash flow from
    midstream services               | $ | 16,573                     | $          | 8,723                   | 90  | $ | 42,644    | $          | 8,804   | 384 
|and marketing (1)                                   |   |                            |            |                         |     |   |           |            |         |     
|Total cash flow from                                | $ | 58,371                     | $          | 30,343                  | 92  | $ | 185,246   | $          | 128,365 | 44  
|Per weighted average unit - basic                   | $ | 0.41                       | $          | 0.37                    | 11  | $ | 1.59      | $          | 1.88    | (15)
|by unit                                             |   |                            |            |                         |     |   |           |            |         |     
|Declared distributions
    to unitholders           | $ | 52,064                     | $          | 32,043                  | 63  | $ | 164,628   | $          | 129,612 | 27  
|Per unit                                            | $ | 0.36                       | $          | 0.39                    | (8) | $ | 1.44      | $          | 2.06    | (30)
|                                                    |   |                            |            |                         |     |   |           |            |         |     
|Net income (loss)                                   | $ | 39,179                     | $          | 17,448                  | 131 | $ | 21,682    | $          | 23,439  | (7) 
|Per weighted average unit - basic                   | $ | 0.28                       | $          | 0.21                    | 33  |   | 0.19      | $          | 0.34    | (44)
|Per weighted average unit - diluted                 | $ | 0.28                       | $          | 0.21                    | 33  | $ | 0.19      | $          | 0.34    | (44)
|Capital expenditures                                | $ | 26,471                     | $          | 7,549                   | 251 | $ | 76,321    | $          | 31,628  | 141 
|                                                    |   |                            |            |                         |     |   |           |            |         |     
|Property acquisitions                               | $ | 64,036                     | $          | -                       | -   | $ | 72,745    | $          | -       | -   
|Property dispositions                               | $ | (6,603)                    | $          | -                       | -   | $ | (13,717)  | $          | (9,947) | 38  
|                                                    |   |                            |            |                         |     |   |           |            |         |     
|Long-term debt                                      | $ | 432,206                    | $          | 356,573                 | 21  | $ | 432,206   | $          | 356,573 | 21  
|Unitholders' equity                                 | $ | 1,044,969                  | $          | 564,174                 | 85  | $ | 1,044,969 | $          | 564,174 | 85  
|Weighted average trust units and                    |   |                            |            |                         |     |   |           |            |         |     
|exchangeable shares outstanding                     |   |                            |            |                         |     |   |           |            |         |     
|(000s)                                              |   | 141,328                    |            | 80,926                  | 40  |   | 116,628   |            | 68,448  | 70  
|                                                    |   |                            |            |                         |     |   |           |            |         |     
|(1) see the MD&A for a definition of
    cash flow.



- 2 -

---



|Operational
    highlights                                                                                     |   |                            |   |                         |        |   |        |   |        |       
|-------------------------------------------------------------------------------------------------------------- | - | -------------------------- | - | ----------------------- | ------ | - | ------ | - | ------ | ------
|(000s except per
    unit amounts)                                                                             |   |                            |   |                         |        |   |        |   |        |       
|                                                                                                               |   |                            |   |                        
|                                                                                                               |   | Quarter ended December 31, |   | Year ended December 31,
|COGP and USOGP combined                                                                                        |   |                            |   |                         | (%)    |   |        |   |        | (%)   
|                                                                                                               |   | 2004                       |   | 2003                    | Change |   | 2004   |   | 2003   | Change
|                                                                                                               |   |                            |   |                         |        |   |        |   |        |       
|Daily production                                                                                               |   |                            |   |                         |        |   |        |   |        |       
|Light/medium crude oil (bpd)                                                                                   |   | 14,012                     |   | 6,454                   | 117    |   | 10,146 |   | 6,812  | 49    
|Heavy oil (bpd)                                                                                                |   | 6,536                      |   | 7,151                   | (9)    |   | 6,608  |   | 6,902  | (4)   
|Natural gas liquids (bpd)                                                                                      |   | 1,770                      |   | 1,145                   | 55     |   | 1,494  |   | 1,167  | 28    
|Natural gas (mcf)                                                                                              |   | 7.339                      |   | 68,657                  | (100)  |   | 77,022 |   | 74,596 | 3     
|Oil equivalent (boed)(1)                                                                                       |   | 36,874                     |   | 26,193                  | 41     |   | 31,085 |   | 27,314 | 14    
|Average selling
    price (before hedging)                                                                     |   |                            |   |                         |        |   |        |   |        |       
|Light/medium crude oil ($/bbl)                                                                                 | $ | 45.83                      | $ | 32.79                   | 40     | $ | 45.01  | $ | 36.02  | 25    
|Heavy oil ($/bbl)                                                                                              | $ | 25.33                      | $ | 20.61                   | 23     | $ | 28.72  | $ | 24.74  | 16    
|Corporate oil blend ($/bbl)                                                                                    | $ | 39.31                      | $ | 26.39                   | 49     | $ | 38.59  | $ | 30.77  | 25    
|Natural gas liquids ($/bbl)                                                                                    | $ | 42.80                      | $ | 34.48                   | 24     | $ | 40.68  | $ | 35.87  | 13    
|Natural gas ($/mcf)                                                                                            | $ | 6.56                       | $ | 5.62                    | 17     | $ | 6.60   | $ | 6.63   | -     
|Oil equivalent ($/boe)(1)                                                                                      | $ | 39.50                      | $ | 29.95                   | 32     | $ | 39.12  | $ | 34.88  | 12    
|Netback ($/boe)
    before hedging                                                                             | $ | 22.33                      | $ | 14.99                   | 49     | $ | 22.18  | $ | 20.10  | 10    
|Netback ($/boe) after hedging                                                                                  | $ | 16.58                      | $ | 12.95                   | 28     | $ | 16.31  | $ | 15.19  | 7     
|                                                                                                               |   |                            |   |                         |        |   |        |   |        |       
|Midstream
    services and                                                                                     |   |                            |   |                         |        |   |        |   |        |       
|marketing                                                                                                      |   |                            |   |                         |        |   |        |   |        |       
|Redwater throughput (bpd)                                                                                      |   | 56,452                     |   | 63,616                  | (11)   |   | 55,120 |   | N/A    | -     
|EBITDA (thousands)                                                                                             | $ | 17,957                     | $ | 10,242                  | 75     | $ | 50,085 | $ | 10,242 | 389   
|(1)Provident reports
    barrels of oil equivalent production converting natural gas to oil on a 6:1
    basis |   |                            |  



- 3 -

---



Fourth quarter highlights

The fourth quarter highlights section provides commentary on
the fourth quarter 2004 results compared to the fourth quarter of 2003.
Definitions of terms used in this section, as appropriate, are defined in the
year over year section of the Management's Discussion and Analysis following
later in this press release.

Consolidated cash flow from operations and cash distributions

|(000s except for per unit data)                                        | Three months ended December 31,
|---------------------------------------------------------------------- | -------------------------------
|                                                                       | 2004                           
|Revenue, Cash Flow and
    Distributions                               |                                
|Revenue (net of
    royalties and non -hedging derivative instruments) | $369,435                       
|Cash flow from
    Operations                                          | $58,371                        
|Per weighted average unit - basic1                                     | $0.41                          
|                                                                       |                                
|                                                                       |                                
|Declared
    distributions                                             | $52,064                        
|Per Unit2                                                              | $0.36                          
|                                                                       |                                
|Percent of cash flow distributed                                       | 89%                            
|1 includes exchangeable shares                                         |                                
|2 excludes exchangeable shares                                         |                                

Fourth quarter 2004 cash flow was $58.4 million, 93 percent
above the $30.3 million of cash flow recorded in the fourth quarter of 2003.
COGP 2004 fourth quarter cash flow was $30.3 million, 40 percent above the $21.6
million recorded in the comparable 2003 quarter. The main driver for this
increase was the 41 percent increase in production volumes. The Midstream
business unit added $16.6 million to fourth quarter 2004 cash million, 90
percent above the $8.7 million recorded in the comparable 2003 quarter. The
Midstream cash flow benefited from efficient operations, marketing opportunities
and increased revenues associated with storage and distribution services. Cash
flow from operations also reflects $11.5 million of USOGP cash flow with no
comparative for the like 2003 quarter. Declared distributions in the fourth
quarter of 2004 totaled $52.1 million, 89 percent of cash flow from operations.
This compares to $32.0 million of declared distributions in 2003 that exceeded
cash flow by five percent.

Comparative figures for cash flow from
operations and cash flow per unit for the fourth quarter of 2003 have been
restated to reflect the retroactive application of reclassifying the convertible
debentures to debt and netting $3.0 million of debenture interest from cash flow
from operations.

- 4 -

---



|Net income                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                     |   |                                 |   |           
|-------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------- | - | ------------------------------- | - | ----------
|                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                               |   | Three months ended December 31,
|(000s except per unit data)                                                                                                                                                                                                                                                                                                                                                                                                                                                                                    |   | 2004                            |   | 2003      
|                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                               |   |                                 |   | (Restated)
|Net income                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                     | $ | 39,179                          | $ | 17,448    
|Per
    weighted average unit                                                                                                                                                                                                                                                                                                                                                                                                                                                                                  | $ | 0.28                            | $ | 0.22      
|- basic(1)                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                     |   |                                 |   |           
|Per
    weighted average unit                                                                                                                                                                                                                                                                                                                                                                                                                                                                                  | $ | 0.28                            | $ | 0.22      
|- diluted(2)                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                   |   |                                 |   |           
|                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                               |   |                                 |   |           
|(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.

Net income for the fourth quarter of 2004
increased 124 percent to $39.2 million compared to a $17.4 million of net income
in the comparable 2003 quarter. The fourth quarter earnings reflect the impact
of non-hedging derivative instruments on COGP results as well as significant
income generated from the Midstream business unit.

The COGP business segment contributed $27.6
million of net income, $16.8 million above 2003 fourth quarter income of $9.8
million (as restated). The increase in the fourth quarter of 2004 highlights the
impact of Accounting Guideline 13 "hedging relationships". The guideline
contradicts the matching principal applied in accounting that requires revenues
to be recognized with expenses incurred in a period. As a result of the
guideline, $25 million of pre-tax COGP income was recorded due to the reduction
in unrealized hedging losses (disclosed as financial derivative instruments
recorded on the balance sheet in the quarter accompanied by twelve months of
operations. In summary, the total hedging loss recorded at September 30 against
nine months of operations totaled $97.8 million, including an unrealized loss of
$47.1 million compared to $91 million of hedging loss booked against twelve
months of operations including only $22.1 million of unrealized losses.

The Midstream unit contributed $11.1 million of net income in
the fourth quarter of 2004, as compared to the $7.7 million of net income in the
fourth quarter of 2003.

USOGP contributed $0.5 million of net income in the fourth
quarter of 2004 with no comparative for 2003.

Comparative figures for fourth quarter 2003
net income have been restated to reflect the retroactive application of the new
standard on accounting for convertible debentures that resulted in a reduction
to net income of $3.6 million

- 5 -

---



|Taxes                             |   |                                 |   |         
|--------------------------------- | - | ------------------------------- | - | --------
|                                  |   | Three months ended December 31,
|($000s)                           |   | 2004                            |   | 2003    
|                                  |   |                                 |   |         
|Capital taxes                     | $ | 2,547                           | $ | 887     
|Current and
    withholding taxes |   | 664                             |   | -       
|Future income taxes recovery      | $ | (10,000)                        | $ | (23,241)

Capital taxes in the fourth quarter totaled
$2.5 million, an increase $1.6 million above the $0.9 million recorded in the
fourth quarter of 2003. The increase reflects the impact the growth in our
Canadian asset base has had on the paid up capital of Provident as well as the
increase in the Saskatchewan resource surcharge that is sensitive to crude oil
prices.

The current and withholding taxes total $0.7
million in the fourth quarter of 2004 with no comparative balance in the
comparable 2003 quarter. These taxes arise from Provident's U.S based
operations.

The 2004 fourth quarter future tax recovery of
$10.0 million compares to a $23.2 million future tax recovery in the fourth
quarter of 2003. A significant recovery occurred in the fourth quarter of 2003
due the determination of internal royalty charges that moved more projected
future taxes into lower tax rate years, resulting in a larger recovery.

Interest expense

|                                                           |   | Three months ended December 31,
|---------------------------------------------------------- | - | -------------------------------
|($000s)                                                    |   | 2004                           
|                                                           |   |                                
|Interest on
    long-term bank debt                        | $ | 3,734                          
|Interest on debentures                                     |   | 3,612                          
|Total cash interest                                        |   | 7,346                          
|Non-cash
    accretion and amortization on convertible     |   |                                
|debentures                                                 |   | (292)                          
|Total interest
    including accretion and amortization on |   |                                
|convertible debentures                                     | $ | 7,054                          

Cash interest expense increased for the quarter as compared
to the same quarter in 2003 due to the increase in the overall size of
Provident, with commensurate increases in debt levels. Accretion and
amortization on convertible debentures has resulted from Provident early
adopting and reclassifying the bulk of its subordinated convertible debentures
to long-term debt and an additional portion to equity. The accounting treatment
for these non-cash amounts is more fully discussed in the year over year section
of Management's Discussion and Analysis.

- 6 -

---



Commodity Price Risk Management Program (CPRMP)

In the fourth quarter of 2004 the opportunity cost of hedging
amounted to $18.3 million compared to $4.9 million of costs in the comparable
quarter in 2003.

The COGP business unit recorded a fourth
quarter 2004 opportunity cost of $16.5 million on crude oil ($ 11.35 per barrel)
and an opportunity cost of $2.0 million on natural gas ($0.25 per mcf), compared
to an opportunity cost of $3.9 million for crude oil ($3.12 per barrel) and an
opportunity cost of $1.0 million for natural gas ($0.16 per mcf) in the
comparable quarter in 2003.

The USOGP business unit recorded an opportunity cost of $0.1
million ($0.18 per barrel) in the quarter, all related to crude oil with no
comparative figure for 2003.

The Midstream business unit recorded a gain of
$0.3 million in the quarter primarily on propane and ethane price stabilization
hedging activities. The Midstream unit did not have any hedging activity for the
fourth quarter of 2003.

Foreign exchange hedges have been allocated to the commodity
the hedge related to at the initiation of the transaction.

Provident's Commodity Price Risk Management Program is more
fully discussed in the year over year section of Management's Discussion and
Analysis.

|COGP segment
    review                                                          |   |                                 |   |       |       
|-------------------------------------------------------------------------------- | - | ------------------------------- | - | ----- | ------
|                                                                                 |   |                                 |   |       |       
|Crude oil price                                                                  |   |                                 |   |       |       
|                                                                                 |   |                                 |   |       |       
|COGP                                                                             |   | Three months ended December 31,
|                                                                                 |   |                                 |   |       | %     
|($ per bbl)                                                                      |   | 2004                            |   | 2003  | change
|                                                                                 |   |                                 |   |       |       
|Oil per barrel                                                                   |   |                                 |   |       |       
|WTI
    (US$)                                                                    | $ | 48.27                           | $ | 31.18 | 55    
|Exchange rate (from US$ to Cdn$)                                                 | $ | 1.21                            | $ | 1.32  | (8)   
|WTI
    expressed in Cdn$                                                        | $ | 58.41                           | $ | 41.16 | 42    
|Corporate realized crude oil and natural gas liquids price before hedging (Cdn$) | $ | 35.86                           | $ | 27.02 | 33    
|Corporate realized light/medium oil price before hedging (Cdn$)                  | $ | 42.00                           | $ | 32.79 | 28    
|Corporate realized heavy oil price before hedging (Cdn$)                         | $ | 25.33                           | $ | 20.61 | 23    
|Corporate realized
    natural gas liquids price before hedging (Cdn$)           | $ | 42.66                           | $ | 34.48 | 24    

Provident's realized oil and natural gas
liquids price, prior to the impact of hedging, increased by 33 percent to $35.86
per barrel in the fourth quarter of 2004 compared to $27.02 per barrel in the
fourth quarter of 2003. The 2004 increase related to a higher US$ WTI crude oil
price offset by a stronger Canadian Dollar.

For 2004, the 55 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

- 7 -

---



lower priced heavy oil. Fourth quarter heavy
oil production as a percentage of total crude oil and natural gas liquids
production in 2004 was 37 percent compared to 48 percent of total crude oil and
natural gas liquids production in the comparable 2003 quarter. The decrease in
the year over year percentage of heavy oil production was mainly due to the
effect of the Viracocha and Olympia acquisitions, and drilling results.

Natural gas price

|COGP                                                                         |   | Three months ended December 31,
|---------------------------------------------------------------------------- | - | -------------------------------
|                                                                             |   | 2004                           
|                                                                             |   |                                
|                                                                             |   |                                
|AECO (Cdn$) per
    mcf                                                      | $ | 7.07                           
|Gas revenue per
    mcf (1)(Cdn$)                                            | $ | 6.53                           
|                                                                             |   |                                
|(1) Excluding the
    effects of the commodity price risk management program

Provident's realized natural gas price, excluding hedges,
increased 16 percent in the fourth quarter of 2004 as compared to the fourth
quarter of 2003.

Production

|COGP                           | Three months ended December 31,
|------------------------------ | -------------------------------
|                               | 2004                           
|                               |                                
|                               |                                
|Daily production               |                                
|Crude oil - Light/Medium (bpd) | 9,281                          
|- Heavy (bpd)                  | 6,536                          
|Natural gas liquids (bpd)      | 1,746                          
|Natural gas (mcfd)             | 85,803                         
|Oil equivalent (boed)
    (1)  | 31,864                         

The 2004 fourth quarter 22 percent increase in
daily production to 31,864 boed compared to 26,193 boed in the fourth quarter of
2003 reflects the acquisition of Olympia and Viracocha to the COGP production
base as well as drilling and optimization activities offset by natural
production declines.

- 8 -

---

Revenue and royaltiesRevenue figures are presented net of transportation expense.

|COGP                                     |   | Three months ended December 31,
|---------------------------------------- | - | -------------------------------
|                                         |   | 2004                           
|                                         |   |                                
|Oil                                      |   |                                
|Revenue                                  | $ | 51,125                         
|Cash
    hedging                         |   | (16,511)                       
|Royalties (net of ARTC)                  |   | (10,230)                       
|Net
    revenue                          | $ | 24,384                         
|Net
    revenue (per barrel)             | $ | 16.41                          
|Royalties as a percentage of revenue     |   | 20.0%                          
|                                         |   |                                
|Natural gas                              |   |                                
|Revenue                                  | $ | 51,637                         
|Cash
    hedging                         |   | (2,001)                        
|Amortization of deferred hedging         |   | -                              
|Royalties (net of ARTC)                  |   | (11,107)                       
|Net
    revenue                          | $ | 38,529                         
|Net
    revenue (per mcf)                | $ | 4.95                           
|Royalties as a percentage of revenue     |   | 21.5%                          
|                                         |   |                                
|Natural gas
    liquids                  |   |                                
|Revenue                                  | $ | 6,852                          
|Royalties                                |   | (1,464)                        
|Net
    revenue                          | $ | 5,388                          
|Net
    revenue (per barrel)             | $ | 33.54                          
|Royalties as a percentage of revenue     |   | 21.4%                          
|                                         |   |                                
|Total                                    |   |                                
|Revenue                                  | $ | 109,614                        
|Cash
    hedging                         |   | (18,512)                       
|Amortization of deferred hedging         |   | -                              
|Royalties (net of ARTC)                  |   | (22,801)                       
|Net
    revenue                          | $ | 68,301                         
|Net
    revenue per boe                  | $ | 23.03                          
|Royalties as a
    percentage of revenue |   | 20.8%                          

Quarter over quarter COGP production revenue
has increased by 51 percent to $109.6 million from $72.4 million in 2003. The
increase incorporates the 22 percent increase in production volumes, and a 55
percent increase in WTI crude oil price partially offset by wider differentials
in the quarter. Royalties as a percentage of revenue have remained relatively
constant at 20.8 percent compared to 20.2 percent for the like quarter in 2003.
Net revenue at $68.3 million is 29 percent above the $52.9 million recorded in
fourth quarter 2003. This reflects the increase in production volumes and crude
oil prices offset by a $13.7 million increase in costs associated with hedging
activities.

Production expenses

|COGP                           |   | Three months ended December 31,
|------------------------------ | - | -------------------------------
|($000s except per boe amounts) |   | 2004                           
|Production expenses            | $ | 26,431                         
|Production expenses (per boe)  | $ | 9.02                           

- 9 -

---



Fourth quarter production expenses increased 22 percent to
$26.4 million from $21.7 million in fourth quarter of 2003. The increase
coincides with the equivalent increase in production volumes. On a boe basis
quarter over quarter production expenses are flat. This recognizes the increase
in production volumes absorbing the fixed cost component of operating costs over
a greater volume of barrels of oil equivalent production offset by an increase
in industry costs driven by high commodity prices.

General and administrative

The following table does not incorporate the
COGP portion of non-cash general and administrative expenses associated with
Provident's unit option plan. Fourth quarter non-cash general and administrative
expenses for COGP totaled $0.9 million.

|COGP                                        |   | Three months ended December 31,
|------------------------------------------- | - | -------------------------------
|                                            |   | 2004                           
|($000s except per unit data)                |   |                                
|                                            |   |                                
|Cash general and
    administrative         | $ | 3,918                          
|                                            |   |                                
|Cash general and administrative
    per boe | $ | 1.34                           

Cash general and administrative expenses for
COGP in the fourth quarter decreased eight percent to $3.9 million from $4.2
million recorded in the 2003 comparable quarter. On a boe basis the cash general
and administrative expenses recorded in fourth quarter 2004 decreased 24 percent
to $1.34 from $1.76 in the fourth quarter of 2003. For the fourth quarter of
2004 both the absolute dollars and the per boe charges incorporate a
reclassification of overhead and certain direct charges that should have been
recorded as expenses in the Midstream and USOGP business units in prior
quarters.

|Operating
    netback               |   |                                 |   |        |       
|----------------------------------- | - | ------------------------------- | - | ------ | ------
|                                    |   |                                 |   |        |       
|COGP                                |   | Three months ended December 31,
|                                    |   | 2004                            |   | 2003   | %     
|                                    |   |                                 |   |        | change
|Netback per boe                     |   |                                 |   |        |       
|Gross production revenue            | $ | 37.29                           | $ | 30.04  | 24    
|Royalties (net of ARTC)             |   | (7.78)                          |   | (6.06) | 28    
|Operating costs                     |   | (9.02)                          |   | (8.99) | -     
|Field operating netback             |   | 20.49                           |   | 14.99  | 37    
|                                    |   |                                 |   |        |       
|Realized loss on cash hedging       |   | (6.32)                          |   | (2.01) | 214   
|Operating netback
    after hedging | $ | 14.18                           | $ | 12.98  | 9     
|                                    |   |                                 |   |        |       

The fourth quarter 2004 field operating
netback of $20.49 per boe was 37 percent above the $14.99 per boe in the same
quarter in 2003. The increased field operating netback in the fourth quarter of
2004 reflects a higher WTI crude oil benchmark partially offset by wider
differentials as well as a significant shift in Provident's production mix to
include a greater weighting towards natural gas and lighter grades of crude oil.
Operating netbacks after hedging increased by only eight percent to

- 10 -

---



$14.18 from $12.98 reflecting the fourth quarter opportunity
cost due to hedging of $6.32 per boe compared to $2.01 in the comparable quarter
in 2003.

|Capital
    expenditures                            |   |                                 |   |      
|--------------------------------------------------- | - | ------------------------------- | - | -----
|                                                    |   |                                 |   |      
|COGP                                                |   | Three months ended December 31,
|($000s)                                             |   | 2004                            |   | 2003 
|                                                    |   |                                 |   |      
|Lloydminster                                        | $ | 4,799                           | $ | 1,469
|West central and
    southern Alberta               |   | 8,413                           |   | 3,298
|Southeast and
    southwest Saskatchewan            |   | 8,201                           |   | 1,894
|Office and other                                    |   | 185                             |   | 891  
|Total additions                                     | $ | 21,598                          | $ | 7,552
|                                                    |   |                                 |   |      
|Dispositions (1)                                    | $ | 6,603                           | $ | -    
|                                                    |   |                                 |   |      
|(1) Includes $3.0 million of non
    cash proceeds. |   |                                 |   |      

Provident spent $21.6 million during the
fourth quarter of which $4.8 million was spent in the Lloydminster core area
drilling wells and optimizing production through pump upgrades. Operated and
non-operated drilling projects combined with re-completion and facility projects
accounted for $8.4 million of spending in west central and southern Alberta. The
Company also spent $8.2 million in southeast and southwest Saskatchewan on
shallow gas development, several re-completion projects, facility work and land
purchases.

Provident experienced weather related delays on capital
projects throughout the fourth quarter of 2004. Planned capital expenditures of
approximately $5.9 million have been deferred to 2005.

Provident spent $7.6 million in the fourth quarter of 2003 on
various drilling, recompleting, optimization and facility projects.

U.S. OGP segment

The USOGP business unit incorporates
activities from Provident's subsidiary, Breitburn Energy LP (Breitburn), an oil
and gas exploitation and production business based in Los Angeles, California.
Breitburn was purchased June 15, 2004 and, therefore there are no fourth quarter
comparative figures for 2003.

- 11 -

---

Crude oil price

|($ per bbl)                                                               | Three months ended December 31,
|------------------------------------------------------------------------- | -------------------------------
|USOGP                                                                     |                                
|USOGP realized crude oil and
    natural gas liquids price before hedging |                                
|(Cdn$)                                                                    | $                              

The USOGP crude oil production, represents 94
percent of the production mix and is primarily light, sweet crude which attracts
prices with a very small ($0.60 per barrel) differential to benchmark prices.

Production

|                                                                                              | Three months ended December 31,
|--------------------------------------------------------------------------------------------- | -------------------------------
|USOGP                                                                                         | 2004                           
|Daily production                                                                              |                                
|Crude oil - Light/Medium (bpd)                                                                | 4,730                          
|Natural gas liquids (bpd)                                                                     | 24                             
|Natural gas (mcfd)                                                                            | 1,536                          
|Oil
    equivalent (boed) (1)                                                                 | 5,010                          
|(1) Provident reports equivalent production converting natural
    gas to oil on a 6:1 basis.

USOGP production increased 1,441 boe per day
in the fourth quarter of 2004 when compared to the third quarter of 2004. The
increase is primarily attributable to the Orcutt acquisition which added 1,425
boe day for the period October 4 to December 31, 2004. The exit production rate
for 2004 was approximately 5,200 boe per day.

- 12 -

---

Revenue and royalties

The following table outlines USOGP revenue and royalties by
product line. The table excludes revenues earned from operating certain
properties ($0.3 million) on behalf of third parties.

|                                                                          |                                 |        
|------------------------------------------------------------------------- | ------------------------------- | -------
|USOGP                                                                     | Three months ended December 31,
|($000s except per unit data)                                              |                                 | 2004   
|Oil                                                                       |                                 |        
|Revenue                                                                   | $                               | 23,212 
|Realized loss on
    non-hedging derivative instrument                    |                                 | (81)   
|Royalties                                                                 |                                 | (2,041)
|Net revenue                                                               | $                               | 21,090 
|Net revenue (per barrel)                                                  | $                               | 40.46  
|Royalties as a
    percentage of revenue                                  |                                 | 8.8%   
|                                                                          |                                 |        
|Natural gas                                                               |                                 |        
|Revenue                                                                   | $                               | 1,134  
|Realized loss on
    non-hedging derivative instrument                    |                                 | -      
|Royalties                                                                 |                                 | -      
|Net revenue                                                               | $                               | 1.134  
|Net revenue (per mcf)                                                     | $                               | 6.56   
|Royalties as a
    percentage of revenue                                  |                                 | -      
|                                                                          |                                 |        
|Natural gas liquids                                                       |                                 |        
|Revenue                                                                   | $                               | 118    
|Royalties                                                                 |                                 | -      
|Net revenue                                                               | $                               | 118    
|Net revenue (per barrel)                                                  | $                               | 52.23  
|Royalties as a
    percentage of revenue                                  |                                 | -      
|                                                                          |                                 |        
|Total                                                                     |                                 |        
|Revenue                                                                   | $                               | 24,464 
|Realized loss on
    non-hedging derivative instrument                    |                                 | (81)   
|Royalties                                                                 |                                 | (2,041)
|Net revenue                                                               | $                               | 22,342 
|Net revenue per boe                                                       | $                               | 41.35  
|Royalties as a percentage of revenue                                      |                                 | 8.3    
|Note: the above figures are presented
    net of transportation expenses. |                                 |        

|                                |                    |      
|------------------------------- | ------------------ | -----
|Production
    expenses         |                    |      
|                                |                    |      
|                                |                    |      
|USOGP                           | Three months ended
|                                | December 31,      
|($000s) except per unit amounts |                    | 2004 
|Production expenses             | $                  | 6,989
|Production expenses (per boe)   | $                  | 15.16

- 13 -

---



Production expenses were higher than expected
in the period fourth quarter of 2004 due to less than expected incremental
production from drilling activities as well as the continued increase in the
cost of goods and services driven by the high commodity price environment.
Operating costs were also impacted by a number of higher operating cost crude
oil wells that were returned to production to take advantage of high crude oil
prices

When compared to the third quarter of 2004, operating costs
have decreased by $0.66 per boe, or 4 percent, due to the fixed cost component
of the operating costs being spread out over more barrels.

General and administrative

|USOGP                                       | Three months ended December 31,
|------------------------------------------- | -------------------------------
|($000s) except per unit amounts             |                                
|Cash general and administrative             | $                              
|Cash
    general and administrative per boe | $                              

Cash general and administrative expenses in
the fourth quarter at $2.3 million or $4.91 per boe include additional expenses
for costs that were not adequately accrued from acquisition date to September
30, 2004.

Operating netback

|USOGP                           | Three months ended December 31,
|------------------------------- | -------------------------------
|($ per boe)                     |                                
|Netback                         |                                
|Gross production
    revenue    | $                              
|                                |                                
|Royalties                       |                                
|Operating costs                 |                                
|Field operating
    netback     |                                
|                                |                                
|Cash hedging                    |                                
|Operating netback after hedging | $                              

Operating netbacks in the fourth quarter of 2004 remain strong
driven by high commodity prices partially offset by increased operating costs.

- 14 -

---



|Income taxes and
    cash taxes |                                 |     
|------------------------------- | ------------------------------- | ----
|                                |                                 |     
|USOGP                           | Three months ended December 31,
|($000s)                         |                                 | 2004
|                                |                                 |     
|Current and withholding taxes   | $                               | 718 

Current and withholding taxes include current
US federal and state income taxes as well as accrued or paid US withholding
taxes on payments that have been or will be made from Breitburn Energy LP to
Provident.

Capital expenditures

USOGP capital expenditures for the fourth
quarter of 2004 totaled $63.1 million. This includes $58.5 million for the
Orcutt property acquisition, $3.1 million to increase Breitburn's working
interest in certain wells at West Pico and Sawtelle, and $1.5 million on
drilling, optimization and facility upgrades at West Pico and Santa Fe Springs.
Optimization capital was partially focused at returning previously uneconomic
wells to production to take advantage of the high commodity price environment.

Midstream services and marketing

The fourth quarter of 2004 results for the
Midstream services and marketing business unit reflected in EBITDA, cash flow
and net income benefited from efficient operations, marketing opportunities and
increased revenues associated with storage and distribution services. Fourth
quarter 2004 EBITDA of $18.5 million increased 83 percent from $10.1 million in
the year ago quarter. Cash flow for the fourth quarter of 2004 quarter was $16.6
million 89 percent above the $8.8 million for the fourth quarter 2003. Fourth
quarter net income at $11.1 million was 44 percent above the $7.7 million of net
income recorded in the fourth quarter of 2003.

- 15 -

---



|Consolidated cash flow from operations and cash distributions        |   |                        
|-------------------------------------------------------------------- | - | -----------------------
|                                                                     |   |                        
|                                                                     |   | Year ended December 31,
|($ 000s, except per unit data)                                       |   | 2004                   
|Revenue, Cash Flow and
    Distributions                             |   |                        
|Revenue (net of
    royalties and non-hedging derivative instruments |   |                        
|- see Note 7 of the financial statements)                            | $ | 1,109,857              
|                                                                     |   |                        
|Cash flow from
    operations before changes in working capital      |   |                        
|and site restoration expenditures                                    | $ | 185,246                
|Per weighted average unit - basic1                                   |   | 1.59                   
|Per weighted average unit - diluted1                                 |   | 1.59                   
|Declared
    distributions                                           | $ | 164,628                
|Per Unit - actual2                                                   |   | 1.44                   
|Percent of cash
    flow distributed                                 |   | 89%                    
|1includes exchangeable shares                                        |   |                        
|2excludes exchangeable shares                                        |   |                        

For the year ended December 31, 2004, cash
flow increased 44 percent or $56.9 million to $185.2 million from $128.3 million
for 2003 (per unit in 2004 - $1.59 in 2003 - $1.88). COGP generated $121.1
million, USOGP $21.5 million, and Midstream $42.6 million of cash flow during
2004.

During 2003 COGP generated cash flow of $119.6 million, while
Midstream, owned only for the fourth quarter of 2003, generated cash flow of
$8.8 million and there was no USOGP comparative.

A full year of results from the Midstream
business unit accounted for $33.8 million of the increase in cash flow. Combined
oil and gas operations contributed $23.1 million of the cash flow increase a
result of a 14 percent increase in oil and gas production combined with higher
crude oil prices largely offset by opportunity costs associated with the
Commodity Price Risk Management Program. Opportunity costs under the Commodity
Price Risk Management Program include a $3.2 million cost for Midstream as well
as an increase in 2004 for the oil and gas production business segments to $5.78
per boe from $4.91 per boe in 2003. Per trust unit, the cost decreased to $0.59
per unit in 2004 from $0.71 in 2003 ($68.9 million and $48.9 million
respectively).

Declared distributions in 2004 totaled $164.6
million, 89 percent of cash flow from operations. This compares to $129.6
million of declared distributions in 2003 that exceeded cash flow by one
percent. Provident's objective in 2005 is to distribute between 80 and 95
percent of cash flow as distributions to unitholders.

Management uses cash flow (before changes in
non-cash working capital and site restoration expenditures) to analyze operating
performance. Provident also reviews cash flow in setting monthly distributions
and takes into account cash required for debt repayment and/or capital programs
in establishing the amount to be distributed. Historically Provident has paid
out between 89 percent and 102 percent of its annual cash flow as distributions
to unitholders.

Cash flow as presented does not have any standardized meaning
prescribed by Canadian generally accepted accounting principles (GAAP) and
therefore it may not be comparable with the calculation

- 16 -

---



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.

Distributions

The following table summarizes distributions paid or declared
by the Trust since inception:

|                                                                              |                        | Distribution Amount
|----------------------------------------------------------------------------- | ---------------------- | -------------------
|Record Date                                                                   | Payment Date           | (Cdn$)             
|2004                                                                          |                        |                    
|January 22, 2004                                                              | February 13, 2004      | $0.12              
|February 19, 2004                                                             | March 15, 2004         | 0.12               
|March 19, 2004                                                                | April 15, 2004         | 0.12               
|April 20, 2004                                                                | May 14, 2004           | 0.12               
|May 19, 2004                                                                  | June 15, 2004          | 0.12               
|June 18, 2004                                                                 | July 15, 2004          | 0.12               
|July 20, 2004                                                                 | August 13, 2004        | 0.12               
|August 20, 2004                                                               | September 15,
    2004 | 0.12               
|September 20,
    2004                                                        | October 15, 2004       | 0.12               
|October 20, 2004                                                              | November 15, 2004      | 0.12               
|November 19, 2004                                                             | December 15, 2004      | 0.12               
|December 20, 2004                                                             | January 15, 2005       | 0.12               
|                                                                              |                        |                    
|2004 Cash
    Distributions paid as declared                                  |                        | $1.44              
|                                                                              |                        |                    
|2003 Cash Distributions paid as declared                                      |                        | $2.06              
|2002 Cash
    Distributions paid as declared                                  |                        | $2.03              
|2001
    Cash Distributions paid as declared - March 2001 - December 2001     | $2.54                  | $1.64              
|                                                                              |                        |                    
|Inception to December 31, 2004 - Distributions paid as declared               | $8.07                  | $5.50              
|                                                                              |                        |                    
|*exchange rate based on the Bank
    of Canada noon rate on the payment date.

For Canadian tax purposes 2004 distributions
were determined to be 71 percent taxable and 29 percent a tax deferred return of
capital in the hands of Canadian unitholders. The 2003 comparables were 59
percent and 41 percent respectively. Distributions received by U.S. resident
unitholders in 2004 are classified as 83 percent qualified dividend and 17
percent tax deferred return of capital. The 2003 comparables were 73 percent and
27 percent respectively. In both the Canada and the U.S., the tax-deferred
portion would usually be treated as an adjustment to the cost base of the units.
Unitholders or potential unitholders should consult their own legal or tax
advisors as to their particular income tax consequences of holding Provident
units.

- 17 -

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|Net income                                                                                                                                                                                                                 |                             |                         |   |           
|-------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------- | --------------------------- | ----------------------- | - | ----------
|                                                                                                                                                                                                                           |                             | Year ended December 31,
|(000s, except per unit data)                                                                                                                                                                                               |                             | 2004                    |   | 2003      
|                                                                                                                                                                                                                           |                             |                         |   | (Restated)
|Net income                                                                                                                                                                                                                 | $                           | 21,682                  | $ | 23,439    
|Per weighted
    average unit                                                                                                                                                                                              |                             |                         |   |           
|- basic(1)                                                                                                                                                                                                                 | $                           | 0.19                    | $ | 0.34      
|Per weighted
    average unit                                                                                                                                                                                              |                             |                         |   |           
|-
    diluted(2)                                                                                                                                                                                                           | $                           | 0.19                    | $ | 0.34      
|(1) Based on weighted average number of trust units outstanding
    plus the number of trust units that would be issued upon conversion of
    exchangeable shares.                                                       
|(2)Based on weighted average number of trust units and trust
    units that would be issued upon conversion of exchangeable shares,
    conversion of the convertible debentures and pursuant to the unit option
    plan.
|                                                                                                                                                                                                                           |                             |                         |   |           
|                                                                                                                                                                                                                           | Year ended
    December 31,
|($000s)                                                                                                                                                                                                                    |                             | 2004                    |   | 2003      
|                                                                                                                                                                                                                           |                             |                         |   | (Restated)
|COGP net income (loss)                                                                                                                                                                                                     | $                           | (20,551)                | $ | 15,728    
|USOGP net income                                                                                                                                                                                                           |                             | 9,699                   |   | -         
|Total oil and gas
    net income                                                                                                                                                                                           |                             | (10,852)                |   | 15,728    
|Midstream net
    income                                                                                                                                                                                                   |                             | 32,534                  |   | 7,711     
|                                                                                                                                                                                                                           |                             |                         |   |           
|Net income                                                                                                                                                                                                                 | $                           | 21,682                  | $ | 23,439    

For the year ended December 31, 2004,
consolidated earnings of $21.7 million resulted from Midstream and Marketing and
USOGP net income of $32.5 million and $9.7 million, respectively, offset by a
$20.6 million loss in COGP.

Net income of $32.5 million in the Midstream
business unit reflects a full year of successful operations incorporating
Provident's strategy of achieving a lower risk cash flow stream and the
operational efficiencies achieved by Provident's Midstream unit. The segment has
not been materially impacted by any year over year changes in accounting
policies.

The net combined loss for the year for COGP
and USOGP of $10.9 million compares to net income in 2003 of $15.7 million.
Comparability to prior years is difficult largely due to the implementation of
CICA Accounting Guideline 13, "Hedging relationships" and no comparative figures
for USOGP from 2003. Provident did not apply hedge accounting to the Commodity
Price Risk Management Program and therefore has marked to market the outstanding
derivatives at each quarter end throughout the year. As discussed in the quarter
over quarter analysis, this has had a significant effect on quarterly reporting
of net income. In addition, under accounting guideline 13, Provident's January
1, 2004 mark to market opportunity cost position of $25.1 million was set up as
a deferred derivative loss to be amortized as a non-cash expense over the life
of those derivatives. Amortization of this amount during 2004 resulted in a
further non-cash charge of $23.0 million in 2004. The combined net non-cash
pre-tax charge for the year ended December 31, 2004, attributed to accounting
guideline 13 was $22.1 million. On an after tax basis the impact was $13.6
million for

- 18 -

---



the year ended December 31, 2004. In future
periods, the non-cash mark to market expense or recovery (recorded as loss or
gain on non-hedging derivative instruments) may be significant depending on
Provident's derivative portfolio and the change in market prices during those
periods.







- 19 -

---



In 2003 consolidated net income of $23.4
million was generated by COGP net income of $15.7 million and Midstream income
of $7.7 million. COGP income was reduced by an $18.6 million non-cash charge
associated with the management internalization offset by a $55.1 million future
tax recovery that resulted from changes to Canadian tax legislation. Further,
the 2003 comparative figures for net income have been restated for the
retroactive application of the reclassification of debentures to long-term debt
resulting in an increase in interest expense and amortization of debt issue
costs.

Taxes

|                                  |   | Year ended December 31,
|--------------------------------- | - | -----------------------
|($ 000s)                          |   | 2004                   
|                                  |   |                        
|Capital taxes                     | $ | 5,921                  
|Current and
    withholding taxes |   | 1,282                  
|Future income taxes (recovery)    |   | (40,577)               
|                                  | $ | (33,374)               

Future income taxes arise as a result of the difference
between the accounting and tax bases of the operating companies and
subsidiaries. Payments to the Trust by these subsidiaries are deductible for
income taxes. 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. The 2004
future income tax recovery of $40.6 million compares to a $56.5 million recovery
for the comparable 2003 period. In 2004, the year to date recovery reflects the
losses recorded due to Accounting Guideline 13 in respect of hedging
relationships. Recoveries in both years reflect the deductibility of payments to
the Trust by the operating companies and subsidiaries. The recovery reported in
2003 reflects the federal tax rate reduction from the 2003 federal budget that
reduced federal tax rates on resource profits in future years. Capital taxes
include the Saskatchewan Resource surcharge and federal and provincial large
corporation taxes. Current and withholding taxes reflect U.S. taxes that are
incurred on operations associated with Provident's June 15, 2004 acquisition of
U.S. based BreitBurn Energy. U.S. operations are subject to U.S. federal and
state income taxes. Payments from U.S. entities to Canadian entities are subject
to withholding taxes if the distributions are characterized by U.S. tax
authorities as income or interest.

Interest expense



- 20 -

---



|                                                                       |   | Year ended December 31,
|---------------------------------------------------------------------- | - | -----------------------
|($ 000s, except per unit data)                                         |   | 2004                   
|                                                                       |   |                        
|Interest on bank
    debt                                              | $ | 11,816                 
|Weighted-average
    interest rate on bank debt                        |   | 3.96%                  
|                                                                       |   |                        
|Interest on 10.5%
    convertible debentures                           |   | 5,226                  
|                                                                       |   |                        
|Interest on 8.75%
    convertible debentures                           |   | 6,421                  
|                                                                       |   |                        
|Interest on 8.0%
    convertible debentures                            |   | 2,153                  
|                                                                       |   |                        
|Total cash
    interest                                                |   | 25,616                 
|Weighted average
    interest rate on all long-term debt               |   | 6.05%                  
|                                                                       |   |                        
|Non -cash
    accretion and amortization - convertible debentures      |   |                        
|Accretion expense                                                      |   | 1,373                  
|Amortization of
    deferred debt issue costs                          |   | 1,435                  
|                                                                       |   |                        
|Total interest
    including accretion and amortization on convertible |   |                        
|debentures                                                             | $ | 28,424                 

Interest expense increases for the year reflect corporate growth.

Effective December 31, 2004, the Trust
retroactively adopted the revised CICA Handbook Section 3860, ("HB 3860"),
"Financial Instruments - presentation and disclosure", for finanical instruments
that may be settled at the issuer's option in cash or its own equity. The
revised standard requires the Trust to classify proceeds from convertible
debentures issued in 2002, 2003 and 2004 as either debt or equity based on fair
value measurement and the substance of the contractual arrangement. The Trust
previously presented the convertible debenture proceeds (net of financing costs)
and related interest obligations as equity on the consolidated balance sheet on
the basis that the Trust could settle its obligation in exchange for the trust
units.

The Trust's obligation to make scheduled
payments of principal and interest constitutes a financial liability under the
revised standard and exists until the instrument is either converted or
redeemed. The holders' option to convert the financial liability into trust
units is an embedded conversion option.

On July 6, 2004 the Trust issued $50.0 million
of unsecured subordinated convertible debentures ($48.0 million net of issue
costs) with an 8.0 percent coupon rate maturing July 31, 2009. Issue costs have
been classified as deferred financing charges. These financing charges are
amortized to income on a straight line basis. The debentures may be converted
into trust units at the option of the holder at a conversion price of $12.00 per
trust unit prior to July 31, 2009, and may be redeemed by the Trust under
certain circumstances. The unsecured subordinated convertible debentures were
initially recorded at $48.1 million which is fair value under accounting rules.
The difference between the fair value and proceeds of $1.9 million was recorded
as equity.

- 21 -

---



On September 30, 2003 the Trust issued $75
million of unsecured subordinated convertible debentures ($71.8 million net of
issues costs) with an 8.75 percent coupon rate maturing December 31, 2008. Issue
costs have been classified as deferred financing charges. These financing
charges are amortized to income on a straight line basis. 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. The unsecured subordinated convertible
debentures were initially recorded at fair value under accounting rules of $70.6
million. The difference between the fair value and proceeds of $4.4 million was
recorded as equity.

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. Issue costs
have been classified as deferred financing charges. These financing charges are
amortized to income on a straight line basis. 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 unsecured subordinated convertible debentures were initially
recorded at fair value under accounting rules of $60.6 million. The difference
between the fair value and proceeds of $3.8 million was recorded as equity.

Financial instruments

Commodity price risk management program

For the year ended December 31, 2004 an
opportunity cost of $68.9 million was recorded due to the Commodity Price Risk
Management Program with $65.7 million related to the combined oil and gas
operations and $3.2 million associated with the midstream business unit.

In the oil and gas business units the hedging
cost associated with crude oil totaled $55.3 million ($9.03 per barrel) and
$10.4 million related to natural gas ($0.37 per mcf), combined total was $65.7
million or $5.78 per boe. This loss includes gains of $3.3 million realized on
heavy oil differential contracts. In 2003 the program recorded an opportunity
cost of $48.9 million or $4.91 per boe with $23.9 million related to crude oil
($4.77 per barrel) and $25.0 million related to natural gas ($0.92 per mcf).

In 2004 the Midstream business unit recorded an opportunity
cost of $3.2 million primarily on propane and ethane price stabilization hedging
activities with no comparative for 2003.

Realized gains and losses on foreign exchange
contracts which fixed the exchange rates on foreign currency contracts related
to the commodity price management program have been presented in the hedging
totals of the commodities to which the foreign exchange contract related at the
time of entering the contract.

On a per trust unit basis the opportunity cost of the
Commodity Price Risk Management Program decreased to $0.59 per trust unit in
2004 from $0.71 per trust unit in 2003.

At December 31, 2004 the mark to market value of open
contracts was in a loss position of $24.5 million based on commodity prices
prevailing at that date. This amount has been reflected in the

- 22 -

---



financial statements of the Trust pursuant to Accounting
Guideline 13 and Emerging Issues Committee Abstract 128 in respect of accounting
for financial instruments.

Provident's Commodity Price Risk Management
Program (the "Program") involves a disciplined hedging strategy that utilizes
derivative instruments to assist with more predictable and stable cash
distributions. The hedging strategy protects a percentage of production against
a decline in commodity prices while, with some products, allowing the Trust to
participate in a rising commodity price environment. It provides protection for
pricing margin and inventory values associated with the midstream and marketing
business lines. As well, the strategy reduces Foreign Exchange risk due to the
exposure arising from the conversion of U.S. dollars into Canadian dollars.

We expect continued commodity price volatility
in 2005; as a result Provident will continue to execute the Program. The
financial instruments used to hedge our cash flows will enable Provident to
participate to a greater degree in a rising price market and should somewhat
protect distributions should commodity prices weaken.

The hedging instruments the Trust uses include puts, costless
collars, participating swaps, fixed and indexed referenced pricing.

Acquisitions

Provident completed three major corporate
acquisitions during 2004. On June 1, 2004 Provident closed the concurrent
acquisitions of Olympia Energy Inc, and Viracocha Energy Inc. by way of
amalgamations with Provident Energy Ltd. On June 15, 2004, Provident acquired 92
percent of BreitBurn Energy LLC (BreitBurn), a private company (now a limited
partnership) active in the oil and gas exploitation and production business in
the Los Angeles basin, U.S.A. The three acquisitions added $486.5 million to
property plant and equipment and $228.5 million to goodwill. Other asset and
liability accounts were also assigned values. In total, 39.2 million units were
issued to finance the three acquisitions for ascribed values and cash totaling
$434.9 million, 2.7 million exchangeable shares were issued for ascribed values
totaling $30.2 million and $50.0 million of convertible unsecured subordinated
debentures were issued as part of the BreitBurn financing. The transactions have
all been accounted for using the purchase method.

On October 4, 2004, Provident, through
BreitBurn, closed the acquisition of certain properties in California (the
Orcutt field) for $58.5 million. Provident funded this acquisition for the
Breitburn partnership and as a result increased its investment ownership in
BreitBurn by 2.2 percent to a total of 94.2 percent.

On March 2, 2005, Provident, through Breitburn,
acquired Nautilus Resources, LLC (Nautilus) for C$95.8 million (US$75million).
Nautilus is a U.S. private company with operations focused in the Big Horn and
Wind River Basins of Wyoming. Nautilus is currently producing approximately
2,300 barrels of oil equivalent per day consisting of 99 percent crude oil and
one percent natural gas. The BreitBurn team has experience in the Wyoming basins
through their discovery and exploitation of their Lost Dome field that is
located near Nautilus' assets.

Goodwill

Goodwill representsthe excess of the cost of an acquired enterprise over the net of the
amounts assigned to assets acquired and liabilities assumed,Goodwill arose from the acquisitions of Richland

- 23 -

---



Petroleum Corporation, $13.3 million, and Meota Resources
Corp., $89.1 million in 2002 and from Olympia Energy Inc., $106.5 million, and
Viracocha Energy Inc., $122.0 million in 2004. Goodwill is assessed for
impairment at least annually, and if an impairment exists, it would be charged
to income in the period in which the impairment occurs. Provident engaged an
independent accounting firm to assist in performing an impairment test at year
end. The impairment test includes, amongst other variables, a comparison of the
net book value of the Trust's assets to the market value of the Trust's equity.
Goodwill is not amortized.

Liquidity and capital resources

|                                                                |   | December 31,
|--------------------------------------------------------------- | - | ------------
|($ 000s)                                                        |   | 2004        
|Long-term debt                                                  | $ | 432,206     
|Working capital
    (surplus)/deficit                           |   | 38,677      
|Net debt                                                        |   | 470,883     
|                                                                |   |             
|Equity (at book
    value)                                      |   | 1,044,969   
|                                                                |   |             
|Total
    capitalization at book value                          | $ | 1,515,852   
|                                                                |   |             
|Net debt as a
    percentage of total book value capitalization |   | 31%         

Provident operates three business units with
similar but not identical monthly cash settlement cycles. Provident's working
capital position is impacted by seasonal fluctuations that reflect commodity
price changes, drilling cycles in its oil and gas operations and inventory
balances in its midstream business unit. Provident relies on cash flow from
operations, external lines of credit and access to equity markets to fund
capital programs and acquisitions.

Long-term debt and working capital

As at December 31, 2004 Provident had drawn on
64 percent of its term credit facility of $410.0 million as compared to 71
percent drawn on its $335.0 million term credit facility as at December 31,
2003. The increase in the level of bank debt was due to the increase scale of
operations primarily due to acquisitions. The reduced percentage of the credit
facilities drawn reflects the reduced leverage on the balance sheet. Provident
has grown significantly in 2004 and financed the majority of 2004 acquisitions
with equity. The change in accounting policy reclassified convertible debentures
to long-term debt, excluding a minor equity component. This accounting change is
more fully discussed in the interest expense section above.

At December 31, 2004 Provident had letters of
credit guaranteeing Provident's performance under certain commercial and other
contracts that totaled $31.0 million, increasing bank line utilization to 72
percent. The guarantees are associated with the Midstream business unit and at
December 31, 2003 totaled $12.3 million.

Provident's working capital decreased by $57.2 million as at
December 31, 2004. Of this amount $22.4 million was due to incorporating balance
sheet accounts for unrealized hedging losses as

- 24 -

---



required by the implementation of Accounting
Guideline 13, "Hedging Relationships" and EIC 128 (see changes in accounting
policy in this MD&A), a $7.1 million decrease in petroleum product inventory,
and a $7.0 million increase in declared distributions payable while the balance
was due to changes in other accounts reflecting the increased scale of
activities including capital activities.

Fourth quarter cash flow in 2004 was $58.4
million. The ratio of debt to annualized fourth quarter cash flow was 1.85 to
one, as compared to fourth quarter annualized debt to cash flow in 2003 of 2.9
to one.

Trust units and exchangeable shares

In 2004, the Trust issued 1.6 million units
(conversion amount $15.3 million) on conversion of exchangeable shares to units
and issued 0.1 million units for the quarter (year ended December 31, 2003 - 5.7
million units with a conversion amount of $55.5 million). The Trust also issued
11,378 units on conversion of convertible debentures and 0.6 million units
pursuant to the stock option plan. Details of these issues are outlined in the
notes to the financial statements. 1.9 million units were issued or are to be
issued resulting from Provident's Premium Distribution, Distribution
Reinvestment and Optional Unit Purchase Plan (DRIP) program (proceeds of $19.9
million) (year ended December 31, 2003 - 2.6 million units for proceeds of $27.4
million).

On 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 January 22, 2004 public offering. Proceeds
from the issue were initially used to pay down Provident's bank debt and
throughout 2004 have been used to finance the company's 2004 capital budget.

On June 1, 2004 the Trust issued 13.4 million
units (at an ascribed value of $152.9) and a further 12.8 million units (at an
ascribed value of $145.7 million) as part of the consideration to acquire the
outstanding shares of Olympia Energy Inc. and Viracocha Energy Inc.
respectively. 1.325 million exchangeable shares of Provident Energy Ltd. were
issued pursuant to each transaction as well for a total of 2.65 million
additional exchangeable shares. The Exchangeable Shares will be automatically
exchanged for Trust Units on January 15, 2006, subject to extension at the
option of the Offeror. The exchange ratio for these shares is calculated with
reference to the distributions.

On July 6, 2004 the Trust issued 13.1 million
units at $10.40 per unit for proceeds of $136.2 million ($129.4 million net of
issue costs) pursuant to a June 17, 2004 public offering. Proceeds from the
issue applied to pay down the bridge financing used in the BreitBurn Energy LLC
acquisition.

On October 4, 2004 the Trust closed a bought
deal issuing 11.48 million units at $10.95 per unit for net proceeds (after
underwriters' fees) of $119.4 million. Proceeds were used to fund the Orcutt
acquisition ($58.5 million) and to repay bank debt.

At December 31, 2004 management and directors held
approximately 1.6 percent of the outstanding units and exchangeable shares.

Non-controlling interest

- 25 -

---



Non-controlling interest arose from
Provident's June 15, 2004 acquisition of 92 percent of BreitBurn Energy of Los
Angeles, California. The founders of BreitBurn Energy beneficially own the
non-controlling interest, which share in earnings or losses of BreitBurn. The
non-controlling interest is reduced by distributions.

|                                                        | Year ended December 31,
|------------------------------------------------------- | -----------------------
|($ 000s)                                                |                        
|Opening non-controlling interest,
    June 15, 2004     | $                      
|Non-controlling
    interest in earnings for the period |                        
|Distributions to non-controlling
    interest holders   |                        
|Closing non-controlling interest,
    December 31, 2004 | $                      

Additional investments by Provident in BreitBurn Energy LP
have reduced the non-controlling interest percentage at December 31, 2004 to
approximately 5.8 percent.



- 26 -

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|Capital
    expenditures and funding                                                                                                                                                                     |   |                         |   |          
|-------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------- | - | ----------------------- | - | ---------
|                                                                                                                                                                                                         |   |                         |   |          
|                                                                                                                                                                                                         |   | Year ended December 31,
|($ 000s)                                                                                                                                                                                                 |   | 2004                    |   | 2003     
|Capital Expenditures and Funding                                                                                                                                                                         |   |                         |   |          
|Capital
    Expenditures                                                                                                                                                                                 |   |                         |   |          
|Capital expenditures and reclamation fund contributions                                                                                                                                                  | $ | (79,165)                | $ | (34,120) 
|Property acquisitions                                                                                                                                                                                    |   | (72,745)                |   |          
|Corporate acquisitions                                                                                                                                                                                   |   | (173,657)               |   | (299,002)
|Property dispositions                                                                                                                                                                                    |   | 10,717                  |   | 9,947    
|Net capital
    expenditures                                                                                                                                                                             | $ | (314,850)               | $ | (323,175)
|                                                                                                                                                                                                         |   |                         |   |          
|Funded By                                                                                                                                                                                                |   |                         |   |          
|                                                                                                                                                                                                         |   |                         |   |          
|Cash flow net of
    declared distributions to unitholders and non-controlling interest                                                                                                                  | $ | 19,654                  | $ | (1,247)  
|Proceeds of
    bridge financing                                                                                                                                                                         |   | 158,184                 |   | -        
|Repayment of
    bridge financing                                                                                                                                                                        |   | (158,184)               |   | -        
|Issue of
    convertible debentures, net of cost                                                                                                                                                         |   | 48,000                  |   | 71,800   
|Issue of trust
    units, net of cost; excluding DRIP                                                                                                                                                    |   | 301,110                 |   | 192,854  
|DRIP proceeds                                                                                                                                                                                            |   | 19,866                  |   | 27,408   
|Reimbursement for
    leasehold improvements                                                                                                                                                             |   | -                       |   | 1,437    
|Change in working
    capital                                                                                                                                                                            |   | 3,307                   |   | (18,377) 
|Increase
    (decrease) in bank debt                                                                                                                                                                     |   | (77,087)                |   | 49,300   
|                                                                                                                                                                                                         | $ | 314,850                 | $ | 323,175  
|Note: The above table does not include the amount attributed to acquisitions
    where consideration was paid by issuing units of the
    trust or non-cash consideration
    received for dispositions.

Capital expenditures were funded by a
combination of DRIP proceeds, proceeds received on non-core property
dispositions, cash flow, equity, exchangeable shares and debt. Provident's
strategy is to fund acquisitions by accessing the capital markets and to fund
capital expenditures through DRIP and other equity if needed.



- 27 -

---

Net asset value

Provident's net asset value ("NAV")as at
December 31, 2004, is summarized in the table below. The NAV is calculated on a
fully diluted basis, which includes exchangeable shares and unit options, and is
presented at eight percent and ten percent discounted cash flow cases. The
pricing used at both December 31, 2004 and December 31, 2003 is derived from the
McDaniel's report.

|($000s except per unit data)                                                                                                           |   | PV 8%     |   | PV 10%   
|-------------------------------------------------------------------------------------------------------------------------------------- | - | --------- | - | ---------
|Net Asset Value:                                                                                                                       |   |           |   |          
|Present value of proved plus probable oil and natural                                                                                  |   |           |   |          
|gas reserves(1)                                                                                                                        | $ | 1,248,161 | $ | 1,134,555
|Midstream assets                                                                                                                       |   | 451,869   |   | 387,360  
|Add:                                                                                                                                   |   |           |   |          
|Land(3)(4)                                                                                                                             |   | 71,652    |   | 71,652   
|Proceeds from Options                                                                                                                  |   | 57,252    |   | 57,252   
|Cash Reserved for Future Reclamation                                                                                                   |   | 1,454     |   | 1,454    
|Investments                                                                                                                            |   | 3,000     |   | 3,000    
|Less:                                                                                                                                  |   |           |   |          
|Financial Hedging Losses                                                                                                               |   | (22,498)  |   | (22,295) 
|Long Term Debt                                                                                                                         |   | (432,206) |   | (432,206)
|Working (Deficiency) Capital                                                                                                           |   | (38,677)  |   | (38,677) 
|Minority Interest                                                                                                                      |   | (13,649)  |   | (13,649) 
|                                                                                                                                       |   |           |   |          
|Consolidated
    Provident Net Asset Value                                                                                             | $ | 1,326,358 | $ | 1,148,446
|                                                                                                                                       |   |           |   |          
|Consolidated
    Provident Net Asset Value per Unit                                                                                    | $ | 8.78      | $ | 7.61     
|                                                                                                                                       |   |           |   |          
|2003
    comparatives                                                                                                                  |   |           |   |          
|Consolidated
    Provident Net Asset Value per Unit                                                                                    | $ | 6.41      | $ | 5.55     
|                                                                                                                                       |   |           |   |          
|(1) Evaluated by McDaniel,s, NSA and CGA ; pricing is McDaniel pricing
      effective December 31, 2004                              
|(2) The Midstream assets represent a discounted cash flow stream (EBITDA
      less maintenance capital) of $39.7 million for 25 years
|(3) Canadian land holdings evaluated by Seaton Jordan & Associates Ltd.
      effective December 31, 2004                             
|(4) U.S. land holdings are included at the market value assigned at the
      date of acquisitions                                    

- 28 -

---



|Asset retirement
    obligation                        |   |                         |   |        
|------------------------------------------------------ | - | ----------------------- | - | -------
|                                                       |   |                         |   |        
|                                                       |   | Year ended December 31,
|($ 000s)                                               |   | 2004                    |   | 2003   
|Carrying amount, beginning of
    period               | $ | 33,182                  | $ | 32,645 
|Oil and gas
    corporate acquisitions                 |   | 12,171                  |   | -      
|Change in
    estimate                                 |   | (2,429)                 |   | -      
|Increase in
    liabilities incurred during the period |   | 166                     |   | 519    
|Settlement of
    liabilities during the period        |   | (4,971)                 |   | (2,153)
|Accretion expense                                      |   | 2,387                   |   | 2,171  
|Carrying amount,
    end of period                     | $ | 40,506                  | $ | 33,182 

The asset retirement obligation (ARO) increased by $7.3
million to $40.5 million during 2004. The Trust's asset retirement obligation is
based on the Trust's net ownership in wells, facilities and the midstream assets
and represents management's estimate of the costs to abandon and reclaim those
wells, facilities and midstream assets as well as an estimate of the future
timing of the costs to be incurred. Estimated cash flows have been discounted at
the Trust's credit-adjusted risk free rate of seven percent and an inflation
rate of two percent.

The total undiscounted amount of future cash
flows required to settle asset retirement obligations related to oil and gas
operations is estimated to be $130.4 million. Payments to settle oil and gas
asset retirement obligations occur over the operating lives of the assets
estimated to be from two to 20 years.

The total undiscounted amount of future cash
flows required to settle the midstream asset retirement obligations is estimated
to be $26.1 million. The estimated costs include such activities as dismantling,
demolition and disposal of the facilities as well as remediation and restoration
of the surface land. Payments to settle the Midstream asset retirement
obligations are expected to occur subsequent to the closure of the facilities
and related assets. Settlement from the balance sheet date of these obligations
is expected to occur over 30 to 35 years.

Non-cash general and administrative

Non-cash general and administrative includes
expenses or recoveries associated with Provident's unit option plan. Provident
accounts for the unit option plan using the fair value of the option, at the
time of issue. Compensation expense associated with the options is deferred and
recognized in earnings over the vesting period of the options. Provident
recorded an expense of $1.8 million for the year ended December 31, 2004 (2003 -$1.3 million).

- 29 -

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Canadian OGP business unit (COGP)



The following prices are net of transportation expense.

|($per bbl)                                                                      |   | Year ended December 31, |  
|------------------------------------------------------------------------------- | - | ----------------------- | -
|COGP                                                                            |   | 2004                    |  
|Oil per barrel                                                                  |   |                         |  
|WTI (US$)                                                                       | $ | 41.43                   | $
|Exchange rate
    (from US$ to Cdn$)                                            | $ | 1.30                    | $
|WTI expressed in
    Cdn$                                                       | $ | 53.86                   | $
|                                                                                |   |                         |  
|COGP realized
    crude oil and natural gas liquids price before hedging (Cdn$) | $ | 36.81                   | $
|                                                                                |   |                         |  
|COGP realized
    light/medium oil price before hedging (Cdn$)                  | $ | 42.79                   | $
|                                                                                |   |                         |  
|COGP realized
    heavy oil price before hedging (Cdn$)                         | $ | 28.72                   | $
|                                                                                |   |                         |  
|COGP realized
    natural gas liquids price before hedging (Cdn$)               | $ | 40.61                   | $

For the year ended December 31, 2004
Provident's pre-hedged oil and natural gas liquids price increased by 20 percent
to average $36.81 compared to $30.77 in 2003. This reflects a 34 percent
increase in the U.S. dollar denominated WTI partly offset by the increase in
value of the Canadian dollar versus the U.S. dollar, and significantly increased
differentials between WTI and realized heavy oil prices.

Natural gas price

The following prices are net of transportation expense.

|($per mcf)                              |   | Year ended December 31,
|--------------------------------------- | - | -----------------------
|COGP                                    |   | 2004                   
|                                        |   |                        
|AECO monthly
    index (Cdn$) per mcf   | $ | 6.79                   
|Corporate natural
    gas price per mcf |   |                        
|before
    hedging (Cdn$)               | $ | 6.59                   

For 2004 the per mcf pre-hedged natural gas price of $6.59
received by Provident was comparable to the $6.63 per mcf received in 2003.

- 30 -

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|Production                                                                                    |                         |        |         
|--------------------------------------------------------------------------------------------- | ----------------------- | ------ | --------
|                                                                                              |                         |        |         
|                                                                                              | Year ended December 31,
|COGP                                                                                          | 2004                    | 2003   | % Change
|Daily production                                                                              |                         |        |         
|Crude oil - Light/Medium (bpd)                                                                | 7,995                   | 6,812  | 17      
|- Heavy (bpd)                                                                                 | 6,608                   | 6,902  | (4)     
|Natural gas liquids (bpd)                                                                     | 1,482                   | 1,167  | 27      
|Natural gas (mcfd)                                                                            | 76,174                  | 74,596 | 2       
|Oil equivalent (boed)
    (1)                                                                 | 28,781                  | 27,314 | 5       
|(1) Provident reports
    equivalent production converting natural gas to oil on a 6:1 basis.

For 2004, Provident's COGP production averaged
28,781 boed, consistent with 2003. Excluding the volumes associated with the
acquisitions, Provident's previous production base decreased due primarily to
natural production declines and dispositions offset by volumes added through
development activities. Additions to production through internal capital
replaced approximately 40 percent of proved plus probable reserves. Provident's
2004 development activities were hampered by poor weather conditions in the
first, second, and fourth quarters, which delayed overall development
activities. Production volumes added from the Olympia and Viracocha acquisitions
also contributed to the replacement of production declines.

Provident's production of approximately 31,500
boed as at December 31, 2004 is approximately 20 percent above the 2003 exit
production level of 26,190 boed. Production as at December 31, 2004 is weighted
44 percent natural gas, 35 percent medium/light crude oil and natural gas
liquids and 21 percent conventional heavy oil. Provident does not have any
single property providing greater than 10 percent of daily production.

- 31 -

---



|Revenue and
    royalties                                                                     |   |                         |   |          |       
|--------------------------------------------------------------------------------------------- | - | ----------------------- | - | -------- | ------
|                                                                                              |   |                         |   |          |       
|                                                                                              |   |                         |   |          |       
|COGP                                                                                          |   | Year ended December 31,
|($ 000s except per boe data)                                                                  |   | 2004                    |   | 2003 %   | Change
|Oil                                                                                           |   |                         |   |          |       
|Revenue                                                                                       | $ | 194,366                 | $ | 151,874  | 28    
|Realized loss on
    non-hedging derivative instruments                                       |   | (54,997)                |   | (23,892) | 130   
|Royalties (net of
    ARTC)                                                                   |   | (38,885)                |   | (29,156) | 33    
|Net revenue                                                                                   | $ | 100,484                 | $ | 98,826   | 2     
|Net revenue (per
    barrel)                                                                  | $ | 18.80                   | $ | 19.74    | (5)   
|Royalties as a
    percentage of revenue                                                      |   | 20.0                    |   | 19.2     |       
|                                                                                              |   |                         |   |          |       
|Natural gas                                                                                   |   |                         |   |          |       
|Revenue                                                                                       | $ | 183,704                 | $ | 180,590  | 2     
|Realized loss on
    non-hedging derivative instruments                                       |   | (10,369)                |   | (25,042) | (59)  
|Royalties (net of
    ARTC)                                                                   |   | (40,813)                |   | (39,190) | 4     
|Net revenue                                                                                   | $ | 132,522                 | $ | 116,358  | 14    
|Net revenue (per
    mcf)                                                                     | $ | 4.75                    | $ | 4.24     | 12    
|Royalties as a
    percentage of revenue                                                      |   | 22.2                    |   | 21.7     |       
|                                                                                              |   |                         |   |          |       
|Natural gas
    liquids                                                                       |   |                         |   |          |       
|Revenue                                                                                       | $ | 22,024                  | $ | 15,282   | 44    
|Royalties                                                                                     |   | (5,492)                 |   | (4,523)  | 21    
|Net revenue                                                                                   | $ | 16,532                  | $ | 10,759   | 10,759
|Net revenue (per
    barrel)                                                                  | $ | 30.48                   | $ | 25.25    | 21    
|Royalties as a
    percentage of revenue                                                      |   | 24.9                    |   | 29.6     |       
|                                                                                              |   |                         |   |          |       
|Total                                                                                         |   |                         |   |          |       
|Revenue                                                                                       | $ | 400,094                 | $ | 347,746  | 15    
|Realized loss on
    non-hedging derivative instruments                                       |   | (65,366)                |   | (48,934) | 34    
|Royalties (net of
    ARTC)                                                                   |   | (85,190)                |   | (72,869) | 17    
|Net revenue                                                                                   | $ | 249,538                 | $ | 225,943  | 10    
|Net revenue per
    boe                                                                       | $ | 23.69                   | $ | 22.58    | 5     
|Royalties as a percentage of
    revenue                                                      |   | 21.3                    |   | 21.0     |       
|Note: the above figures are
    presented net of transportation expenses and service revenue. |  

Total COGP revenue for the 2004 was $249.5
million, an increase of 10 percent from $225.9 million for 2003. The increased
revenue reflects a five percent increase in production volumes and increased
crude oil prices partly offset by higher cash hedging losses. Average royalty
rates remained comparable in total year over year.

- 32 -

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|Production
    expenses       |   |                         |   |        |         
|----------------------------- | - | ----------------------- | - | ------ | --------
|                              |   |                         |   |        |         
|                              |   |                         |   |        |         
|COGP                          |   | Year ended December 31,
|(000s, except per boe data)   |   | 2004                    |   | 2003   | % change
|Production
    expenses       | $ | 90,330                  | $ | 76,396 | 18      
|Production expenses (per boe) | $ | 8.58                    | $ | 7.66   | 12      

In 2004 COGP operating costs increased 18
percent to $90.3 million from $76.4 million in 2003. This increase reflects a
five percent gain in production volumes, an increase in optimization activities
and higher costs for field services. On a per boe basis costs increased to $8.58
per boe or 12 percent above the $7.66 per boe recorded in 2003. The increase in
per boe costs includes an increase in power, processing, servicing and workover
activity driven largely by the higher commodity price environment. Operating
costs for 2005 in a high commodity price environment with increased levels of
activity are forecast to average $8.75 per boe to $9.25 per boe.

General and administrative

The following table does not incorporate the
COGP portion of non-cash general and administrative charges associated with
Provident's unit option plan. A non-cash expense of $0.9 million was recorded in
2004.

|COGP                                    |   | Year ended December 31,
|--------------------------------------- | - | -----------------------
|($ 000s, except per boe data)           |   | 2004                   
|Cash general and administrative         | $ | 16,439                 
|Cash general and administrative per boe | $ | 1.56                   

In 2004 COGP general and administrative
expenses increased 15 percent to $16.4 million compared to $14.3 million in
2003. The increase in general and administrative expenses reflects additional
costs associated with an increase in staff, rent, insurance and compliance and
reporting costs. The Canadian operations are capable of absorbing additional
production, particularly in existing core areas, with little impact on general
and administrative expenses. For 2005 costs per boe are forecast to increase as
a result of further increases in costs associated with compliance (including
costs associated with the implementation of procedures and documentation to be
in compliance with the U. S. Sarbanes-Oxley Act), and a more competitive
landscape impacting the cost of hiring and compensating employees.

- 33 -

---

Operating netback

COGP operating netbacks have transportation expense netted
against gross production revenue.

|($ per boe)                     |   | Year ended December 31,
|------------------------------- | - | -----------------------
|COGP                            |   | 2004                   
|Netback per boe                 |   |                        
|Gross production
    revenue    | $ | 37.99                  
|                                |   |                        
|Royalties (net of
    ARTC)     |   | (8.08)                 
|Operating costs                 |   | (8.58)                 
|Field operating netback         |   | 21.33                  
|                                |   |                        
|Realized loss on cash hedging   |   | (6.18)                 
|Operating netback after hedging | $ | 15.15                  

For the year ended December 31, 2004 the field
operating netback increased six percent to $21.33 per boe. Higher commodity
prices more than offset increases in royalties and operating costs. Netbacks
after hedging cost were lower than the comparable 2003 period at $15.15 per boe
versus $15.19 per boe. The decrease in the netback is due to higher field
revenues being more than offset by higher royalties, operating costs and
opportunity costs on hedging.

Depletion, depreciation and accretion (DD&A)

|($000s, except per boe data |   | Year ended December 31,
|--------------------------- | - | -----------------------
|COGP                        |   | 2004                   
|                            |   |                        
|DD&A                        | $ | 160,271                
|                            |   |                        
|DD&A per boe                | $ | 15.21                  

The COGP DD&A rate increased to $15.21 per boe
compared to $13.65 per boe for 2003. The increase is mainly due to the cost of
acquiring proved reserves in 2004 in western Canada in an environment where
reserve costs escalated with higher commodity prices. The result was proved
reserves in 2004 were acquired at a higher cost per boe than Provident's
historical asset base.

In 2004 DD&A also includes accretion expense associated with
asset retirement obligation of $2.4 million versus $2.2 million in 2003.

- 34 -

---



|Capital
    expenditures                                                           |   |                         |   |        
|---------------------------------------------------------------------------------- | - | ----------------------- | - | -------
|                                                                                   |   |                         |   |        
|                                                                                   |   |                         |   |        
|($000s)                                                                            |   | Year ended December 31,
|COGP                                                                               |   | 2004                    |   | 2003   
|Lloydminster                                                                       | $ | 10,215                  | $ | 12,200 
|West central and
    southern Alberta                                              |   | 24,299                  |   | 11,936 
|Southeast and
    southwest Saskatchewan                                           |   | 25,810                  |   | 3,854  
|Office and other                                                                   |   | 1,130                   |   | 3,638  
|Total additions                                                                    | $ | 61,454                  | $ | 31,628 
|Property acquisitions                                                              | $ | 5,873                   | $ | -      
|Dispositions (1)                                                                   | $ | (13,717)                | $ | (9,947)
|(1) Includes $3.0 million of
    non-cash proceeds on a disposition - see note 13.

In 2004, Provident's COGP business unit spent
$10.2 million in the Lloydminster core area on drilling, recompletions,
equipping and seismic activity. In the west central area $9.5 million was spent
largely on non-operated capital and in the southern Alberta core area $14.8
million went toward drilling activities, recompletions and facility upgrades.
Provident spent $25.8 million in the southeast and southwest Saskatchewan core
areas on acquiring mineral rights for future development, drilling for shallow
gas and recompletions. Office and other accounted for $1.1 million of capital.

In 2004 asset dispositions of non-core assets
totaled $13.7 million compared to $9.9 million in 2003. For the year ended
December 31, 2003, Provident incurred capital expenditures of $31.6 million, of
which $12.2 million was spent in the Lloydminster core area drilling 28 net
heavy oil wells, as well as on land and seismic. In west central and southern
Alberta $11.9 million was spent on operated and non-operated drilling projects
as well as on facility and optimization projects and land purchases. Southeast
and southwest Saskatchewan capital expenditures of $3.9 million were directed at
drilling, recompletions and facility projects. The remaining $3.6 million was
spent primarily on Provident's head office move and leasehold improvements.

In 2003 $9.9 million of assets were disposed of that primarily
related to the sale of acreage with a risk profile that did not meet internal
criteria.

Provident's capital expenditures are partly
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 directed proceeds from the DRIP
program of $19.9 million in 2004 (2003 - $27.4 million), along with the proceeds
from asset dispositions, towards the capital expenditure budget.

The 2005 capital budget approved by the Board of Director's
for COGP is $68.8 million.

- 35 -

---

United States OGP business unit

The USOGP business unit incorporates
activities from Provident's subsidiary, BreitBurn Energy LP (BreitBurn), an oil
and gas exploitation and production business based in Los Angeles, California. A
majority stake in BreitBurn was purchased June 15, 2004.

Crude oil price

|                                                                                 |   | Year ended  
|-------------------------------------------------------------------------------- | - | ------------
|($ per bbl)                                                                      |   | December 31,
|USOGP                                                                            |   | 2004        
|Oil per barrel                                                                   |   |             
|WTI (US$)                                                                        | $ | 41.43       
|Exchange rate
    (from US$ to Cdn$)                                             | $ | 1.30        
|WTI expressed in
    Cdn$                                                        | $ | 53.86       
|USOGP realized
    crude oil and natural gas liquids price before hedging (Cdn$) | $ | 53.24       
|USOGP realized
    light/medium oil price before hedging (Cdn$)                  | $ | 52.42       
|USOGP realized natural gas
    liquids price before hedging (Cdn$)               | $ | 49.33       

|                                                                                               |                  
|---------------------------------------------------------------------------------------------- | -----------------
|Production                                                                                     |                  
|                                                                                               |                  
|                                                                                               | For the period of
|                                                                                               | June 15, 2004 to 
|                                                                                               | December 31,     
|USOGP                                                                                          | 2004             
|Daily production                                                                               |                  
|Crude oil -
    Light/Medium (bpd)                                                             | 3,954            
|Natural gas
    liquids (bpd)                                                                  | 23               
|Natural gas (mcfd)                                                                             | 1,559            
|Oil equivalent (boed) (1 )                                                                     | 4,237            
|(1 ) Provident reports
    equivalent production converting natural gas to oil on a 6:1 basis.

The daily production figures in this section are for the June
to December period. The effect of the production from U.S. operations on
consolidated daily production is on an annual basis.

Excluding the Orcutt acquisition, USOGP
production increased by approximately four percent or 158 boe per day in the
period June 15 to December 31, 2004. The increase in base production is
primarily attributable to drilling and optimization programs at West Pico and
Santa Fe Springs offset by natural production declines. The Orcutt acquisition
added 1,425 boe per day for the period October 4, to December 31, 2004. The exit
production rate for 2004 was approximately 5,200 boe per day.

- 36 -

---

Revenue and royalties

The following table outlines USOGP revenue and
royalties by product line. The table excludes revenues earned from operating
certain properties (of $0.6 million year to date) on behalf of third parties.

|                                                                          |   | Year ended  
|------------------------------------------------------------------------- | - | ------------
|USOGP                                                                     |   | December 31,
|($ 000s, except per boe amounts)                                          |   | 2004        
|Oil                                                                       |   |             
|Revenue                                                                   | $ | 41,983      
|Realized loss on
    non-hedging derivative instrument                    |   | (425)       
|Royalties                                                                 |   | (4,009)     
|Net revenue                                                               | $ | 37,549      
|Net revenue (per barrel)                                                  | $ | 47.72       
|Royalties as a
    percentage of revenue                                  |   | 9.5         
|                                                                          |   |             
|Natural gas                                                               |   |             
|Revenue                                                                   | $ | 2,482       
|Realized loss on
    non-hedging derivative instrument                    |   | -           
|Royalties                                                                 |   | -           
|Net revenue                                                               | $ | 2,482       
|Net revenue (per mcf)                                                     | $ | 8.00        
|Royalties as a
    percentage of revenue                                  |   | 0           
|                                                                          |   |             
|Natural gas
    liquids                                                   |   |             
|Revenue                                                                   | $ | 223         
|Royalties                                                                 |   | -           
|Net revenue                                                               | $ | 223         
|Net revenue (per barrel)                                                  | $ | 49.28       
|Royalties as a
    percentage of revenue                                  |   | 0           
|                                                                          |   |             
|Total                                                                     |   |             
|Revenue                                                                   | $ | 44,688      
|Realized loss on
    non-hedging derivative instrument                    |   | (425)       
|Royalties                                                                 |   | (4,009)     
|Net revenue                                                               | $ | 40,254      
|Net revenue per boe                                                       | $ | 47.74       
|Royalties as a percentage of
    revenue                                  |   | 9.0         
|Note: the above figures are
    presented net of transportation expenses. |   |             
|                                                                          |   |             
|                                                                          |   |             
|Production
    expenses                                                   |   |             
|                                                                          |   |             
|                                                                          |   | Year ended  
|USOGP                                                                     |   | December 31,
|($ 000s, except per boe amounts)                                          |   | 2004        
|Production expenses                                                       | $ | 13,173      
|Production expenses (per boe)                                             | $ | 15.62       

USOGP Production expenses are higher than expected in the
period June 15 to December 31, 2004 due to less than expected incremental
production from certain drilling activities as well as continuing

- 37 -

---



increases in the cost of goods and services
due to the high commodity price environment. BreitBurn also returned some higher
operating cost wells to production due to the current high commodity price
environment. Operating costs for 2005 are expected to average between $13.00 and
$13.50, at a USD$1.00=CAD$1.25 exchange rate, primarily due to projected
increases in production.

General and administrative

The following table does not incorporate the
USOGP portion of non-cash general and administrative charges associated with the
USOGP unit appreciation rights plan and an internal management charge. A year to
date non-cash expense for the unit appreciation rights plan and the internal
management charge of $0.8 million and $0.7 million respectively has been
recorded in 2004.

|                                            |   | Year ended  
|------------------------------------------- | - | ------------
|USOGP                                       |   | December 31,
|($ 000s, except per boe amounts)            |   | 2004        
|Cash general and administrative             | $ | 4,113       
|Cash general and administrative
    per boe | $ | 4.85        

General and administrative expenses in the
USOGP unit are expected to increase slightly in absolute terms with the Nautilus
acquisition (which was completed March 2, 2005), but to slightly decrease on a
per unit (boe) basis. The U.S. operations are capable of absorbing additional
production, particularly in core areas, with minor increases in general and
administrative expenses.

Operating netback

|                                |   | Year ended  
|------------------------------- | - | ------------
|USOGP                           |   | December 31,
|($ per boe)                     |   | 2004        
|Netback per boe                 |   |             
|Gross production
    revenue    | $ | 52.92       
|Royalties                       |   | (4.76)      
|Operating costs                 |   | (15.62)     
|Field operating
    netback     |   | 32.54       
|Cash hedging                    |   | (0.79)      
|Operating netback after hedging | $ | 31.75       

Despite higher than expected operating costs, USOGP operating
netbacks remained strong throughout 2004 due to high commodity prices.

- 38 -

---



|Income taxes and
    cash taxes |   |             
|------------------------------- | - | ------------
|                                |   |             
|                                |   | Year ended  
|USOGP                           |   | December 31,
|($ 000s)                        |   | 2004        
|                                |   |             
|Current and withholding taxes   | $ | 1,201       

Current and withholding taxes include current
U.S. federal and state income taxes as well as accrued or paid U.S. withholding
taxes on distributions that have been or will be made from BreitBurn Energy LP
to Provident.

Depletion, depreciation and accretion (DD&A)

|                                 |   | Year ended  
|-------------------------------- | - | ------------
|USOGP                            |   | December 31,
|($ 000s, except per boe amounts) |   | 2004        
|                                 |   |             
|DD&A                             | $ | 7,402       
|DD&A per boe                     | $ | 8.78        

The USOGP's DD&A rate is low due to the long-lived nature of
the assets.

Capital expenditures

USOGP capital expenditures for the year ended
December 31, 2004 totaled $79.3 million. This includes $59.5 million for the
Orcutt property acquisition, $3.1 million to increase BreitBurn's working
interest in certain wells at West Pico and Sawtelle, $7.3 million on drilling,
optimization and facility upgrades at West Pico, $5.0 million on drilling,
optimization and facility upgrades at Santa Fe Springs and $4.4 million on
facility upgrades, acquisitions and optimization programs at other USOGP
properties. Optimization capital was partially focused at returning previously
uneconomic wells to production due to the high commodity price environment.

Oil and natural gas reserves

In order to provide clarity in Provident's
reserve reporting, the reserves are illustrated by country and on a consolidated
basis. The Canadian and U.S evaluation reports used the McDaniel & Associates
(McDaniel) price forecast at January 1, 2005 and are prepared in accordance with
disclosure standards as mandated by the Canadian Securities Administrators'
National Instrument 51-101 (NI 51-101) Standards of Disclosure for Oil and Gas
Activities. NI-51-101 establishes prescribed disclosures regarding oil and
natural gas information and provides enhanced corporate governance measures by
mandating the involvement of independent reserves evaluators in the preparation
of reserves data and assigning responsibility for the content of reserves data
directly to management and the board of directors.

- 39 -

---



Under NI-51-101, proved reserves are defined as having a high
degree of certainty to be recoverable and probable reserves are defined as those
reserves that are less certain to be recovered than proved reserves. The
targeted levels of certainty, in aggregate, are at least 90 percent probability
that the quantities actually recovered will equal or exceed the estimated proved
reserves and at least a 50 percent probability that the quantities recovered
will equal or exceed the sum of the estimated proved plus probable reserves. The
most significant aspect of reporting under NI-51-101 standards is the definition
of proved plus probable as a "best estimate" of future recoverable reserves.

Provident consolidated oil and natural gas reserves

Provident had a very successful year with
respect to reserves addition activities and the drive to continually support the
sustainability of the trust. The Trust's reserves more than doubled after
production with proved producing reserves growing from 35,466 Mboe to 73,715
Mboe, total proved growing from 41,868 Mboe to 99,627 Mboe, and proved plus
probable growing from 54,894 Mboe to 130,800 Mboe. Reserve life indices
increased as well largely due to the acquisition of low decline, long life
reserves in the U. S. Acquisitions accounted for most of the growth in reserves
volumes however it is noteworthy that internal development activities in Western
Canada were successful in replacing approximately 36 percent of total
production. NI 51-101 requires that acquisitions be reported as per the
evaluation completed at the time of the year-end filing. To comply with this
requirement all 2004 acquisitions are summarized herein as per the McDaniel,
Cawley, Gillespie and Associates, Inc. (CGA) and Netherland, Sewell and
Associates, Inc. (NSA) December 31, 2004 evaluations with actual production
added back to develop the effective volumes acquired at the time of acquisition.
These volumes may be different than those presented in press releases at the
time of acquisition due to different effective dates, impacting production as
well as technical and economic revisions. Additional reserves detail can be
found in the Trust's Annual Information Form.

Canadian oil and natural gas reserves

Provident's Canadian oil and natural gas
reserves as of December 31, 2004 were evaluated or reviewed by McDaniel.
McDaniel evaluated the properties that comprise approximately 81 percent of the
value of the Canadian oil and gas reserves. The remaining 19 percent of value
was evaluated by qualified Provident staff and ultimately reviewed by McDaniel.
In 2003 a similar approach was taken with McDaniel evaluating approximately 75
percent of Provident's Canadian properties.

Total proved reserves increased by 49 percent and proved plus
probable reserves increased by 44 percent, before accounting for production, and
24 percent and 25 percent respectively after production. Acquisitions were the
major factor accounting for 77 percent of the total proved and 83 percent of the
proved plus probable increases before production. Additions due to drilling made
a significant contribution with total proved additions replacing 29 percent of
production and proved plus probable additions replacing 39 percent of Canadian
production. Revisions, excluding economic factors, accounted for a 3 percent
increase in total proved reserves and minus 1 percent for proved plus probable
reserves. Higher commodity prices resulted in positive revisions due to economic
factors of approximately 2 percent. Production in 2004 totaled 10,534 Mboe and
along with acquisitions and divestitures, additions and revisions, resulted in a
proved plus probable reserve closing balance at December 31, 2004 of 68,672 Mboe
compared to 54,894 Mboe on December 31, 2003.

- 40 -

---



United States

Provident's U. S. oil and natural gas reserves
as of December 31, 2004 were evaluated by NSA and CGA. NSA evaluated properties
that comprise approximately 90 percent of the value of the U. S. reserves with
CGA evaluating the remainder. The U. S. reserves evaluations comply with NI
51-101 and both companies are qualified to evaluate reserves in accordance with
the Canadian reporting requirements.

The increase in commodity prices between the
acquisition dates and year-end, when applied to the shallow decline rates of the
United States reserves, resulted in significant positive revisions due to
economic factors. These factors resulted in a 15 percent increase in the proved
developed producing and total proved reserves, and a 16 percent increase in
proved plus probable reserves over the assignments at the time of purchase.

Provident consolidated oil and natural gas reserves

The following reconciliation summarizes Provident's consolidated reserve
activity for the year ended December 31, 2004, on the basis of working interest,
and net interest after royalties.

Provident consolidated(d) Proved developed producing

|                             | Light &       |               |               |          |       |         
|---------------------------- | ------------- | ------------- | ------------- | -------- | ----- | --------
|                             | Medium        | Heavy         | Total         |          |       |         
|Company Share (WI +RI)(a)(c) | Crude
    Oil | Crude
    Oil | Crude
    Oil | Gas      | NGL   | BOE     
|                             | Mbbl          | Mbbl          | Mbbl          | MMcf     | Mbbl  | Mboe    
|Balance at December 31, 2003 | 11,195        | 3,937         | 15,132        | 109,019  | 2,164 | 35,466  
|Production                   | (3,598)       | (2,482)       | (6,080)       | (28,435) | (542) | (11,361)
|Acquisition                  | 33,999        | 2,146         | 36,145        | 44,517   | 1,208 | 44,772  
|Divestiture                  | (148)         | (1)           | (149)         | (910)    | (21)  | (321)   
|Exploration
    Discoveries  | 0             | 0             | 0             | 763      | 22    | 149     
|Drilling Extensions          | 262           | 692           | 954           | 2,285    | 36    | 1,370   
|Recompletion                 | 197           | 73            | 270           | 2,580    | 9     | 709     
|Transfer                     | 0             | 186           | 186           | 164      | 0     | 213     
|Economic Factors             | 491           | 223           | 714           | 1,031    | 10    | 896     
|Technical Revisions          | 1,044         | 396           | 1,440         | 1,929    | 60    | 1,822   
|Balance at December 31, 2004 | 43,442        | 5,169         | 48,611        | 132,943  | 2,947 | 73,715  
|(WI)Share(b)                 |               |               |               |          |       |         
|Balance at December 31, 2004 | 43,393        | 5,158         | 48,551        | 130,972  | 2,902 | 73,281  

-41-

---

Provident consolidated(d) Total proved

|                              | Light &   |           |             |          |       |         
|----------------------------- | --------- | --------- | ----------- | -------- | ----- | --------
|                              | Medium    | Heavy     | Total Crude |          |       |         
|Company Share (WI +RI) (a)(c) | Crude Oil | Crude Oil | Oil         | Gas      | NGL   | BOE     
|                              | Mbbl      | Mbbl      | Mbbl        | MMcf     | Mbbl  | Mboe    
|Balance at December 31, 2003  | 11,773    | 7,473     | 19,246      | 122,093  | 2,273 | 41,868  
|Production                    | (3,598)   | (2,481)   | (6,080)     | (28,435) | (542) | (11,361)
|Acquisition                   | 46,286    | 4,669     | 50,956      | 67,782   | 1,981 | 64,234  
|Divestiture                   | (148)     | (153)     | (301)       | (910)    | (21)  | (473)   
|Exploration Discoveries       | 0         | 0         | 0           | 763      | 22    | 149     
|Drilling Extensions           | 262       | 835       | 1,097       | 6,133    | 36    | 2,156   
|Recompletion                  | 197       | 73        | 270         | 2,972    | 9     | 774     
|Transfer                      | 0         | 3         | 3           | 0        | 0     | 3       
|Economic Factors              | 492       | 265       | 757         | 1,030    | 10    | 938     
|Technical Revisions           | 1,062     | (38)      | 1,024       | 1,272    | 103   | 1,339   
|                              |           |           |             |          |       |         
|Balance at December 31, 2004  | 56,324    | 10,646    | 66,971      | 172,700  | 3,873 | 99,627  
|                              |           |           |             |          |       |         
|(WI) Share (b)                |           |           |             |          |       |         
|Balance at December 31, 2004  | 56,252    | 10,634    | 66,887      | 170,318  | 3,824 | 99,097  

Provident consolidated(d) Total proved plus probable

|                                  | Light &       |                 |               |          |       |         
|--------------------------------- | ------------- | --------------- | ------------- | -------- | ----- | --------
|                                  | Medium        | Heavy
    Crude | Total         |          |       |         
|Company Share (WI
    +RI) (a)(c) | Crude
    Oil | Oil             | Crude
    Oil | Gas      | NGL   | BOE     
|                                  | Mbbl          | Mbbl            | Mbbl          | MMcf     | Mbbl  | Mboe    
|Balance at December 31, 2003      | 14,971        | 11,875          | 26,846        | 151,392  | 2,816 | 54,894  
|Production                        | (3,598)       | (2,482)         | (6,080)       | (28,435) | (542) | (11,361)
|Acquisition                       | 57,233        | 8,164           | 65,397        | 89,034   | 2,832 | 83,067  
|Divestiture                       | (167)         | (538)           | (704)         | (1,013)  | (24)  | (897)   
|Exploration
    Discoveries       | 0             | 0               | 0             | 916      | 27    | 179     
|Drilling Extensions               | 321           | 1,074           | 1,395         | 8,512    | 57    | 2,870   
|Recompletion                      | 202           | 92              | 294           | 4,522    | 11    | 1,059   
|Transfer                          | 0             | 8               | 8             | 0        | 0     | 8       
|Economic Factors                  | 679           | 410             | 1,089         | 1,130    | 10    | 1,287   
|Technical Revisions               | 488           | (724)           | (237)         | (804)    | 64    | (307)   
|                                  |               |                 |               |          |       |         
|Balance at December 31, 2004      | 70,128        | 17,880          | 88,007        | 225,252  | 5,251 | 130,800 
|                                  |               |                 |               |          |       |         
|(WI) Share
    (b)                |               |                 |               |          |       |         
|Balance at December 31, 2004      | 70,043        | 17,865          | 87,908        | 222,343  | 5,189 | 130,155 

(a)

- 42 -

---

Provident's Consolidated oil and natural gas reserves and present value of
estimated future cash flows based on forecast (escalated) price assumptions are
summarized below.
Provident consolidated reserves summary(a)(b)Using McDaniel
January 1, 2004 Forecast Pricing

|                |               | Gross Reserves(c) |               |        |         |         | Net Reserves(d) |        |               |       
|--------------- | ------------- | ----------------- | ------------- | ------ | ------- | ------- | --------------- | ------ | ------------- | ------
|                |               |                   |               |        |         |         |                 |        |               |       
|                |               |                   |               |        |         |         |                 |        |               |       
|                |               |                   |               |        |         |         |                 |        |               |       
|                |               |                   |               |        |         |         |                 |        |               |       
|                |               |                   |               |        |         |         | Light
    &     |        |               |       
|                | Light
    &   | Heavy             |               |        |         |         | Medium          | Heavy  |               |       
|                | Medium        | Crude             |               |        |         |         | Crude           | Crude  |               |       
|                | Crude
    Oil | Oil               | Total
    Oil | NGLs   | Gas     | Boe     | Oil             | Oil    | Total
    Oil | NGLs  
|                | (mbbl)        | (mbbl)            | (mbbl)        | (mbbl) | (mmcf)  | (mboe)  | (mbbl)          | (mbbl) | (mbbl)        | (mbbl)
|Proved Reserves |               |                   |               |        |         |         |                 |        |               |       
|                |               |                   |               |        |         |         |                 |        |               |       
|Producing       | 43,393        | 5,158             | 48,551        | 2,902  | 130,972 | 73,281  | 39,053          | 4,532  | 43,585        | 2,258 
|                |               |                   |               |        |         |         |                 |        |               |       
|Non-Producing   | 4,229         | 690               | 4,919         | 185    | 21,421  | 8,674   | 3,870           | 580    | 4,450         | 147   
|                |               |                   |               |        |         |         |                 |        |               |       
|Undeveloped     | 8,630         | 4,787             | 13,417        | 738    | 17,924  | 17,142  | 7,153           | 4,333  | 11,486        | 603   
|                |               |                   |               |        |         |         |                 |        |               |       
|Total Proved    | 56,252        | 10,634            | 66,887        | 3,824  | 170,318 | 99,097  | 50,075          | 9,445  | 59,520        | 3,008 
|                |               |                   |               |        |         |         |                 |        |               |       
|Probable        | 13,791        | 7,231             | 21,022        | 1,365  | 52,026  | 31,058  | 12,049          | 6,541  | 18,599        | 1,078 
|TOTAL Proved    |               |                   |               |        |         |         |                 |        |               |       
|plus Probable   | 70,043        | 17,865            | 87,908        | 5,189  | 222,343 | 130,155 | 62,124          | 15,986 | 78,110        | 4,086 

(a)

- 43 -

---



Provident consolidated present value of reserves (a)(b)(c)

|                               |            | Present Worth Value Before Tax
    Discounted at |              
|------------------------------ | ---------- | ------------------------------------------------ | -------------
|                               | 0 %        | 8%                                               | 10 %         
|                               |            |                                                  | ($
    000's)
|Proved Reserves                |            |                                                  |              
|Producing                      | $1,123,630 | $828,534                                         | $777,562     
|Non-Producing                  | 125,043    | 72,478                                           | 65,379       
|Undeveloped                    | 300,677    | 159,591                                          | 135,085      
|Total Proved                   | 1,549,350  | 1,060,603                                        | 978,026      
|Probable                       | 607,083    | 308,538                                          | 266,933      
|TOTAL Proved plus
    Probable | $2,156,432 | $1,369,141                                       | $1,244,959   
|                               |            |                                                  |              
|                               |            |                                                  |              
|                               |            | Present Worth Value After Tax(d)                 | Discounted at
|                               | 0 %        | 8%                                               | 10 %         
|                               |            |                                                  | ($
    000's)
|Proved Reserves                |            |                                                  |              
|Producing                      | $1,090,901 | $802,947                                         | $752,816     
|Non-Producing                  | 76,391     | 42,293                                           | 37,569       
|Undeveloped                    | 257,912    | 136,346                                          | 114,587      
|Total Proved                   | 1,425,203  | 981,587                                          | 904,973      
|Probable                       | 527,922    | 266,574                                          | 229,582      
|TOTAL Proved plus
    Probable | $1,953,124 | $1,248,161                                       | $1,134,555   

(a)

Provident's Canadian oil and natural gas reserves and present
value of estimated future cash flows based on forecast (escalated) price
assumptions are summarized below.

- 44 -

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Canada reserves summary(a)

|                |         | Gross Reserves |        |        |         |        | Net Reserves |        |        |       
|--------------- | ------- | -------------- | ------ | ------ | ------- | ------ | ------------ | ------ | ------ | ------
|                |         |                |        |        |         |        |              |        |        |       
|                | Light & |                |        |        |         |        | Light &      |        |        |       
|                | Medium  | Heavy          |        |        |         |        | Medium       | Heavy  |        |       
|                | Crude   | Crude          |        |        | Natural |        | Crude        | Crude  |        |       
|                | Oil     | Oil            | Oil    | NGLs   | Gas     | Boe    | Oil          | Oil    | Oil    | NGLs  
|                | (mbbl)  | (mbbl)         | (mbbl) | (mbbl) | (mmcf)  | (mboe) | (mbbl)       | (mbbl) | (mbbl) | (mbbl)
|Proved Reserves |         |                |        |        |         |        |              |        |        |       
|Producing       | 15,258  | 3,509          | 18,766 | 2,828  | 123,228 | 42,132 | 13,010       | 3,022  | 16,032 | 2,195 
|Non-Producing   | 498     | 683            | 1,181  | 185    | 20,550  | 4,790  | 437          | 573    | 1,010  | 147   
|Undeveloped     | 255     | 2,817          | 3,072  | 131    | 7,264   | 4,413  | 221          | 2,521  | 2,743  | 104   
|Total Proved    | 16,011  | 7,008          | 23,019 | 3,144  | 151,042 | 51,336 | 13,668       | 6,117  | 19,784 | 2,446 
|Probable        | 4,021   | 4,315          | 8,336  | 994    | 44,163  | 16,690 | 3,437        | 3,860  | 7,298  | 773   
|                |         |                |        |        |         |        |              |        |        |       
|                |         |                |        |        |         |        |              |        |        |       
|TOTAL Proved    |         |                |        |        |         |        |              |        |        |       
|plus Probable   | 20,032  | 11,323         | 31,355 | 4,137  | 195,204 | 68,026 | 17,105       | 9,977  | 27,082 | 3,218 

(a)

Canada present value of reserves (a)(b)

|                  |            | Present Worth Value Before Tax(c) | Discounted at |         
|----------------- | ---------- | --------------------------------- | ------------- | --------
|                  | 0 %        | 8%                                | 10 %          | 15 %    
|                  |            |                                   | ($
    000's) |         
|Proved Reserves   |            |                                   |               |         
|Producing         | $787,859   | $611,739                          | $582,441      | $523,289
|Non-Producing     | 57,745     | 39,867                            | 37,083        | 31,647  
|Undeveloped       | 51,028     | 35,757                            | 33,037        | 27,435  
|Total Proved      | 896,632    | 687,363                           | 652,561       | 582,371 
|Probable          | 295,481    | 173,312                           | 156,536       | 125,489 
|TOTAL Proved plus |            |                                   |               |         
|Probable          | $1,192,112 | $860,675                          | $809,097      | $707,860

(a)

Provident's U. S. oil and natural gas reserves
and present value of estimated future cash flows based on forecast (escalated)
price assumptions are summarized below. Reserves and values reported are based
on 100 percent of the interests of Breitburn L.P. in the U.S. properties as at
December 31, 2004. Provident indirectly holds approximately 94.2 percent of the
outstanding partnership interests of Breitburn L.P. with the remaining
approximately 5.8 percent of the partnership interests held by Breitburn's
co-founders and co-chief executive officers.

- 45 -

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United States reserves summary(a)(b)

|                |         |                |        |        |         |        |              |        |        |        |         |       
|--------------- | ------- | -------------- | ------ | ------ | ------- | ------ | ------------ | ------ | ------ | ------ | ------- | ------
|                |         | Gross Reserves |        |        |         |        | Net Reserves |        |        |       
|                |         |                |        |        |         |        |              |        |        |        |         |       
|                | Light & |                |        |        |         |        | Light &      |        |        |        |         |       
|                | Medium  | Heavy          |        |        |         |        | Medium       | Heavy  |        |        |         |       
|                | Crude   | Crude          |        |        | Natural |        | Crude        | Crude  |        |        | Natural |       
|                | Oil     | Oil            | Oil    | NGLs   | Gas     | Boe    | Oil          | Oil    | Oil    | NGLs   | Gas     | Boe   
|                | (mbbl)  | (mbbl)         | (mbbl) | (mbbl) | (mmcf)  | (mboe) | (mbbl)       | (mbbl) | (mbbl) | (mbbl) | (mmcf)  | (mboe)
|Proved Reserves |         |                |        |        |         |        |              |        |        |        |         |       
|Producing       | 28,135  | 1,649          | 29,784 | 74     | 7,744   | 31,149 | 26,043       | 1,510  | 27,554 | 63     | 6,601   | 28,717
|Non-Producing   | 3,731   | 7              | 3,738  | 0      | 872     | 3,884  | 3,433        | 7      | 3,439  | 0      | 752     | 3,565 
|Undeveloped     | 8,375   | 1,970          | 10,345 | 606    | 10,660  | 12,728 | 6,931        | 1,812  | 8,743  | 499    | 8,766   | 10,703
|Total Proved    | 40,241  | 3,626          | 43,868 | 681    | 19,276  | 47,761 | 36,407       | 3,329  | 39,736 | 562    | 16,119  | 42,985
|Probable        | 9,770   | 2,916          | 12,686 | 371    | 7,863   | 14,367 | 8,611        | 2,681  | 11,292 | 306    | 6,523   | 12,685
|                |         |                |        |        |         |        |              |        |        |        |         |       
|                |         |                |        |        |         |        |              |        |        |        |         |       
|TOTAL Proved    |         |                |        |        |         |        |              |        |        |        |         |       
|plus Probable   | 50,011  | 6,542          | 56,554 | 1,052  | 27,139  | 62,128 | 45,019       | 6,009  | 51,028 | 868    | 22,642  | 55,670

(a)

(b)Reserves and values reported
are based on 100 percent of the interests of Breitburn L.P. in the U.S.
properties as at December 31, 2004. Provident indirectly holds approximately
94.2 percent of the outstanding partnership interests of Breitburn L.P. with the
remaining approximately 5.8 percent of the partnership interests held by
Breitburn's co-founders and co-chief executive officers.

United States present value of reserves (a)(b)(d)

|                               |                                               | Present Worth Value Before Tax Discounted at |          
|------------------------------ | --------------------------------------------- | -------------------------------------------- | ---------
|                               | 0 %                                           | 8%                                           | 10 %     
|                               |                                               |                                              | ($ 000's)
|Proved Reserves                |                                               |                                              |          
|Producing                      | $335,771                                      | $216,795                                     | $195,120 
|Non-Producing                  | 67,298                                        | 32,611                                       | 28,296   
|Undeveloped                    | 249,649                                       | 123,834                                      | 102,048  
|Total Proved                   | 652,718                                       | 373,240                                      | 325,465  
|Probable                       | 311,602                                       | 135,226                                      | 110,398  
|TOTAL Proved plus
    Probable | $964,320                                      | $508,466                                     | $435,862 
|                               |                                               |                                              |          
|                               |                                               |                                              |          
|                               | Present Worth Value After Tax(c)Discounted at
|                               | 0 %                                           | 8%                                           | 10 %     
|                               |                                               |                                              | ($ 000's)
|Proved Reserves                |                                               |                                              |          
|Producing                      | $303,042                                      | $191,208                                     | $170,375 
|Non-Producing                  | 18,646                                        | 2,426                                        | 486      
|Undeveloped                    | 206,884                                       | 100,589                                      | 81,550   
|Total Proved                   | 528,571                                       | 294,224                                      | 252,411  
|Probable                       | 232,441                                       | 93,262                                       | 73,046   
|TOTAL Proved plus
    Probable | $761,012                                      | $387,486                                     | $325,458 

- 46 -

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(a)

The following table summarizes the McDaniel's price forecast used in
evaluating Provident's reserves under escalated pricing assumptions:

Reserves pricing summary

|     |               | WTI @    |                  |                 |                 
|---- | ------------- | -------- | ---------------- | --------------- | ----------------
|     |               | Cushing  | Light,
    Sweet | Heavy
    Oil @ | Alberta
    AECO
|     | US$/Cdn$      | Oklahoma | @
    Edmonton   | Hardisty        | Spot
    Price  
|     | Exchange Rate | US$/bbl  | Cdn$/bbl         | Cdn$/bbl        | Cdn$/GJ         
|2005 | 0.83          | 42.00    | 49.60            | 29.40           | 6.45            
|2006 | 0.83          | 39.50    | 46.60            | 29.90           | 6.20            
|2007 | 0.83          | 37.00    | 43.50            | 27.90           | 6.05            
|2008 | 0.83          | 35.00    | 41.10            | 26.30           | 5.80            
|2009 | 0.83          | 34.50    | 40.50            | 25.90           | 5.70            

National Instrument 51-101

Oil and natural gas reserves estimation and
reporting had been governed by National Policy 2B (NP 2B) from the late 1970's
until 2003. As a result of concern expressed by many market participants over
the quality and consistency of oil and gas reserves estimates, the Alberta
Securities Commission established the Oil and Gas Taskforce in June 1998. The
Taskforce, working with the Canadian Institute of Mining, Metallurgy & Petroleum
(CIM), and the Calgary chapter of the Society of Petroleum Evaluations Engineers
developed recommendations to standardize reserve definitions, as well as the
Canadian Oil and Gas Evaluation ("COGEH") handbooks to provide guidance for
engineers and geologists on recommended reserves booking practices. The Canadian
Securities Association proposed new standards that govern all aspects of
reserves disclosure in the form of National Instrument 51-101 (NI 51-101). The
evaluation practices applied to all of Provident's reserves comply with NI
51-101.

Reserve definitions

The following outlines the main reserves definitions as per NI
51-101.

Acquisitions and Dispositions: Positive or negative changes to
the reserves estimates as a result of purchasing or selling all or a portion of
an interest in oil and gas properties.

Closing Balance: Company or net interest reserves assigned at
the end of the period being reconciled.

- 47 -

---



Company Share: Includes working interest volumes and volumes
equivalent to royalty interests (RI) paid to others, but excludes volumes
equivalent to royalty interests received from others.

Drilling Extensions: Additions to reserves resulting from
capital expenditures for step-out drilling in previously discovered reservoirs.

Economic Factors: Changes to reserves between the current and
previous reporting periods resulting from different price forecasts, inflation
rates, and regulatory changes.

Exploration Discoveries: Additions to reserves where no
reserves were previously booked.

Improved Recovery: Additions to reserves
resulting from capital expenditures associated with the installation of enhanced
recovery schemes that were not previously included in reserves in that category.

Infill Drilling: Additions to reserves
resulting from capital expenditures for infill drilling in previously discovered
reservoirs that were not drilled for enhanced recovery schemes and that were not
previously included in the initial reserves assignment.

Net Share: Includes the Company's working interests and
volumes equivalent to royalty interests received from others, but excludes
volumes equivalent to royalty interests (RI) paid to others.

Opening Balance: Company or net interest reserves reported in
the evaluation being reconciled to.

Production: Reserves reductions due to production during the
time period being reconciled.

Technical Revisions: Positive or negative reserves revisions
to a reserves entity resulting from new technical data or revised
interpretations on previously assigned reserves.

Working Interest: The Company's interest before royalties paid
to or received from others.

Reserve life index ("RLI")

The 2004 year end RLI's were determined by
applying the average 2005 production rate from the McDaniel, NSA and CGA
evaluations to the remaining volumes as of January 1, 2005. The proved plus
probable RLI's for years prior to 2003 are based on established reserves under
NP 2B with probable reserves risked at 50 percent.

It is important to note that the long-term,
stable cash flow from the midstream services business significantly extends
Provident's economic life. For this reason economic life as a measure of
Provident's future cash flows is more representative than the typically
referenced reserve life index.

- 48 -

---



The following table illustrates the reserve volume and reserve
life index for Provident since its inception as a trust.

Provident consolidated reserve life index Company share (WI + RI)

|                       |      |      | December 31, |     
|---------------------- | ---- | ---- | ------------ | ----
|                       |      |      |              |     
|Total Crude oil        | 2004 | 2003 | 2002         | 2001
|Proved Producing       | 7.2  | 3.6  | 3.7          | 4.0 
|Total Proved           | 9.0  | 4.6  | 4.9          | 6.6 
|Proved plus Probable   | 11.0 | 6.4  | 5.9          | 8.3 
|                       |      |      |              |     
|Natural gas liquids    |      |      |              |     
|Proved Producing       | 4.9  | 5.3  | 4.8          | 4.6 
|Total Proved           | 6.1  | 5.6  | 5.2          | 5.3 
|Proved plus Probable   | 8.1  | 6.9  | 6.0          | 6.3 
|                       |      |      |              |     
|Natural gas            |      |      |              |     
|Proved Producing       | 4.9  | 4.9  | 5.9          | 4.8 
|Total Proved           | 5.6  | 5.5  | 6.8          | 5.6 
|Proved plus Probable   | 6.9  | 6.8  | 7.7          | 6.7 
|                       |      |      |              |     
|Oil equivalent (6:1)   |      |      |              |     
|Proved Producing       | 6.2  | 4.3  | 4.7          | 4.3 
|Total Proved           | 7.5  | 5.0  | 5.7          | 6.3 
|Proved plus Probable   | 9.3  | 6.6  | 6.7          | 7.8 
|                       |      |      |              |     
|Economic Life Index(a) | 13.4 | 11.2 | 6.7          | 7.8 

(a) Economic Life Index is based on a 25 year life for the Redwater
facilities which Provident acquired in 2003 with Oil & Gas and Midstream
weighting based on net present value discounted at 10%.

Canada reserve life index 
Company share (WI + RI)

|                     | December 31,
|-------------------- | ------------
|                     |             
|Total Crude oil      | 2004        
|Proved
    Producing | 3.8         
|Total Proved         | 4.3         
|Proved plus Probable | 5.4         
|                     |             
|Natural gas liquids  |             
|Proved
    Producing | 4.8         
|Total Proved         | 4.7         
|Proved plus Probable | 6.0         
|                     |             
|Natural gas          |             
|Proved
    Producing | 4.8         
|Total Proved         | 5.1         
|Proved plus Probable | 6.3         
|                     |             
|Oil equivalent (6:1) |             
|Proved
    Producing | 4.3         
|Total Proved         | 4.7         
|Proved plus Probable | 5.8         

- 49 -

---



United States reserve life index Company share (WI + RI)

|                     |      |      | December 31, |     
|-------------------- | ---- | ---- | ------------ | ----
|                     |      |      |              |     
|Total Crude oil      | 2004 | 2003 | 2002         | 2001
|Proved
    Producing | 16.9 | --   | --           | --  
|Total Proved         | 22.1 | --   | --           | --  
|Proved plus Probable | 26.9 | --   | --           | --  
|                     |      |      |              |     
|Natural gas liquids  |      |      |              |     
|Proved
    Producing | 8.9  | --   | --           | --  
|Total Proved         | 15.0 | --   | --           | --  
|Proved plus Probable | 22.1 | --   | --           | --  
|                     |      |      |              |     
|Natural gas          |      |      |              |     
|Proved Producing     | 12.0 | --   | --           | --  
|Total Proved         | 22.3 | --   | --           | --  
|Proved plus Probable | 27.2 | --   | --           | --  
|                     |      |      |              |     
|Oil equivalent (6:1) |      |      |              |     
|Proved Producing     | 16.6 | --   | --           | --  
|Total Proved         | 22.0 | --   | --           | --  
|Proved plus Probable | 26.8 | --   | --           | --  

Finding, development and acquisition costs

Under NI 51-101, the methodology to be used to
calculate finding and development costs ("F&D") implies that F&D and finding,
development and acquisition costs ("FD&A costs") incorporate changes in future
development capital ("FDC") required to bring the proved undeveloped and
probable reserves to production.

Provident had three year average total proved
and probable finding, development and acquisition (FD&A) costs of $10.68 per boe,
including Future Development Costs (FDC) and NI-51-101 revisions. We believe
that taking a three-year average of FD&A is the appropriate method in which to
look at reserve add costs because it takes into account more full cycle
economics as well as the means through which reserves are added.

In 2004 additions due to drilling were a
significant contribution with total proved additions of 3,079 Mboe and proved
plus probable additions of 4,108 Mboe. It is important to recognize is that as
an energy trust and not an exploration oriented venture, Provident is naturally
going to focus capital and other resources on reserve promotes between
categories. In 2004, as a result of infill drilling we promoted over 213 MBOE of
reserves into the proved developed producing category. The associated capital,
and any changes to it, have been accounted for in the NI 51-101 calculation and
is part of the ongoing development process necessary to bring production on
stream and create cash flow.

The table below presents F&D and FD&A costs
for both proven and proved plus probable reserves. Costs include all costs of
exploring for and developing reserves, including land costs. Acquisition costs
include the cash cost of acquiring reserves and the fair value of liabilities
assumed. The requirement under generally accepted accounting principles to
increase the book value of property plant and equipment and to record an
offsetting future tax liability when the purchase price paid on an (usually
corporate) acquisition exceeds the available tax pools. This has not been added
to FD& A costs. Goodwill was recorded on the acquisitions as part of the
purchase price allocation, and therefore

- 50 -

---



forms part of the costs of acquiring the
reserves. NI 51-101 does not specifically define reserve additions and does not
contemplate nor define acquisition costs. The following table presents reserve
additions both including reserve revisions and excluding reserve revisions. If
negative revisions exceed additions, the resultant negative number has been
excluded. In 2003, dispositions of oil and gas reserves exceeded additions, and
have also been excluded from the table.

Provident Consolidated

|($ per boe)                        | 2004   | 2003   | 2002   | average (2)
|---------------------------------- | ------ | ------ | ------ | -----------
|Finding and Development Costs      |        |        |        |            
|per boe(3)
    (includes FDCs)     |        |        |        |            
|Proven                             |        |        |        |            
|Additions                          | $21.20 | $16.20 | $14.39 | $18.24     
|Additions including
    revisions  | $12.19 | - (1)  | - (1)  | - (1)      
|Proved plus
    probable           |        |        |        |            
|Additions                          | $15.84 | $22.05 | $11.01 | $15.42     
|Additions including
    revisions  | $12.79 | $14.63 | - (1)  | - (1)      
|Finding,
    development and       |        |        |        |            
|acquisition costs
    per boe      |        |        |        |            
|(includes FDCs)                    |        |        |        |            
|Proven                             |        |        |        |            
|Proven excluding
    revisions     | $14.55 | - (1)  | $13.95 | $12.63     
|Proven including
    revisions     | $14.25 | - (1)  | $15.30 | $13.28     
|Proved plus
    probable           |        |        |        |            
|Proved plus probable
    excluding |        |        |        |            
|revisions                          | $11.71 | - (1)  | $12.42 | $10.39     
|Proved plus probable
    including |        |        |        |            
|revisions                          | $11.72 | -(1)   | $13.91 | $10.68     

(1) Revisions exceeded additions or dispositions exceeded acquisition,
therefore the calculation is not included in the table 
(2) Three year average is the average of 2002, 2003 and 2004. The aggregate of
the exploration and development costs incurred in the most recent financial year
and the change during that year in estimated future development costs generally
will not reflect total finding and development costs related to reserves
additions for that year. 
(3) Based on Company share reserves. BOEs may be misleading, particularly if
used in isolation. A BOE conversion ratio of 6 Mcf: 1 bbl is based on an energy
equivalency conversion method primarily applicable at the burner tip and does
not represent a value equivalency at the wellhead.

- 51 -

---

Canada
Three
    year($ per boe)
    2004
    2003
    2002
    average (2)Finding and Development Costsper boe(3)
    (includes FDCs)ProvenAdditions
    $21.20
    $16.20
    $14.39
    $18.24Additions including
    revisions
    $12.19
    - (1)
    - (1)
    - (1)Proved plus
    probableAdditions
    $15.84
    $22.05
    $11.01
    $15.42Additions including
    revisions
    $12.79
    $14.63
    - (1)
    - (1)Finding,
    development andacquisition costs
    per boe (includesFDCs)ProvenProven excluding
    revisions
    $27.77
    - (1)
    $13.95
    $18.00Proven including
    revisions
    $24.69
    - (1)
    $15.30
    $19.64Proved plus
    probableProved plus probable
    excludingrevisions
    $21.85
    - (1)
    $12.42
    $15.55Proved plus probable
    includingrevisions
    $20.96
    -(1)
    $13.91
    $16.38

(1) Revisions exceeded additions or dispositions exceeded
acquisition, therefore the calculation is not included in the table 
(2) Three-year average is the average of 2002, 2003 and 2004. The aggregate of
the exploration and development costs incurred in the most recent financial year
and the change during that year in estimated future development costs generally
will not reflect total finding and development costs related to reserves
additions for that year. 
(3) Based on Company share reserves. BOEs may be misleading, particularly if
used in isolation. A BOE conversion ratio of 6 Mcf: 1 bbl is based on an energy
equivalency conversion method primarily applicable at the burner tip and does
not represent a value equivalency at the wellhead.

|United States(1)                                          |      
|--------------------------------------------------------- | -----
|($ per boe)                                               | 2004 
|Finding, development and
    acquisition costs per boe(2) |      
|(includes FDCs)                                           |      
|Proven                                                    |      
|Proven excluding
    revisions                            | $9.89
|Proven including
    revisions                            | $9.89
|Proved plus
    probable                                  |      
|Proved plus probable
    excluding revisions              | $8.19
|Proved plus probable including
    revisions              | $8.19

(1)

- 52 -

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Midstream services and marketing business segment

The assets

The 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:

- 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 direct 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.
- 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.
- 100 percent ownership of the 565 kilometer
  proprietary Liquids Gathering System ("LGS") that runs along the
  Alberta-British Columbia border providing access to a highly active basin for
  liquids-rich natural gas exploration and exploitation. Provident also has
  long-term shipping rights on the Pembina Peace Pipeline that extends the
  product delivery transportation network through to the Redwater fractionation
  facility.

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.

Midstream and marketing services

Provident's midstream services offer 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,
fractionation, short term storage and distribution of their NGL barrels. The NGL
owner is responsible for marketing their product.

Marketing Services: This service involves NGL owners
delivering their product to Provident with Provident taking title and paying the
NGL owner an amount that is a delivery price of raw NGLs that is discounted to
postings. The discounted purchase price that Provident pays for the product
covers the costs of transportation, fractionation, storage, and marketing of the
NGLs.

Storage: NGL owners pay fees to store their NGLs.

Transport and Distribution: NGL owners or purchasers pay fees
to transport NGLs through the LGS pipeline and use rail and truck loading
facilities.

- 53 -

---



Management estimates that marketing of
third-party oil volumes, combined with certain Provident crude oil volumes, will
provide better producer netbacks than can be achieved through third-party
marketers

The contracts

At the Redwater facility, approximately 75
percent of the available capacity is contracted through fee-for-service or fixed
margin arrangements with major oil and natural gas producers and petrochemical
businesses. As a result of these contracts, approximately 68 percent of
Redwater's system capacity is contracted for 10 years or longer.

Fractionation plant capacity and throughput

The 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.

Operations - throughput

In 2004, throughput at the Redwater
fractionation facility averaged 55,120 bpd compared to 63,616 in the fourth
quarter of 2003, the first quarter in which the facility was owned by Provident.
Outages on a liquids gathering system and on a third-party delivery system
contributed to a reduction in mix inventory at the end of the year. These
outages were substantially mitigated through deliveries on alternative
pipelines.

Revenues

2004 product sales and services revenues of
$840.2 million after elimination of intersegment transactions include product
sales related to T&F processing and marketing, revenues generated through
storage and distribution services and oil sales generated through oil marketing
activities. The majority of NGL revenues are earned pursuant to the long-term
contracts and annual evergreen purchase and sales commitments.

Cost of goods sold

The cost of goods sold of $741.6 million after
elimination of intersegment transactions for the year relates to NGL product
sales revenue included in the product sales and services revenue, where
Provident has purchased natural gas liquids and to oil purchased pursuant to oil
marketing activities. 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.

- 54 -

---



Other expenses

The plant has modern technology and low cost
operations compared to other North American facilities of this type. In 2004,
operating costs of $38.0 million included costs associated with a scheduled
turnaround at the Redwater plant. General and administrative expenses of $6.7
million for 2004 (2003 - $1.1 million), interest of $6.7 million for 2004 (year
ended December 31 - $1.4 million), and depreciation of $9.6 million for 2004
(2003 - $2.2 million) consistently show 2004 expenses exceed 2003 expenses
because 2004 reflects a full year of operation compared to three months of
operations in 2003.

Earnings before interest, taxes, depletion, depreciation,
accretion, and non-cash revenue ("EBITDA")and cash flow from operations

For 2004, Provident's Midstream business unit
generated EBITDA of $50.1 million and cash flow from operations of $42.6
million. Actual EBITDA performance exceeded management's 2004 EBITDA forecast of
$38-$42 million. These full year results compare to fourth quarter 2003 EBITDA
of $10.2 million and cash flow of $8.8 million.

Management's 2005 forecast for Midstream EBITDA is $40
million.

Management uses EBITDA to analyze the
operating performance of the midstream business unit. EBITDA as presented does
not have any standardized meaning prescribed by Canadian GAAP and therefore it
may not be comparable with the calculation of similar measures for other
entities. EBITDA as presented is not intended to represent operating cash flow
or operating profits for the period nor should it be viewed as an alternative to
cash flow from operating activities, net earnings or other measures of financial
performance calculated in accordance with Canadian GAAP. All references to
EBITDA throughout this report are based on Earnings before interest, taxes,
depletion, depreciation, accretion, and non-cash revenue ("EBITDA") Provident
foreign ownership developments.

Foreign ownership

Since January 2002, we have seen increased
trading volumes and levels of ownership by nonresidents of Canada. Based on
information received from our transfer agent and financial intermediaries in
March 2005, an estimated 75 percent of our outstanding trust units are held by
nonresidents. However, this estimate may not be accurate as it is based on
certain assumptions and data from the security industry that does not have a
well-defined methodology to determine the residency of beneficial holders of
securities.

In March of 2004, the Canadian government
announced that it would change current legislation to ensure that all mutual
fund trusts, including resources trusts, would be subject to a minimum 50
percent Canadian ownership standard and that there would be withholding taxes on
all distributions to non-residents of Canada. The specific legislation providing
the details of the changes was tabled in mid-September. These changes required
that Provident have no more than 50 percent foreign ownership by January 1,
2007.

- 55 -

---



In December of 2004, Canada's Minister of
Finance tabled a Notice of Ways and Means Motion to Implement Budget 2004
Measures (the Notice). The Notice did not include restrictions upon foreign
ownership of mutual fund trusts as was previously proposed in draft legislation
on September 16, 2004. Under the terms of the Notice, non-resident taxable and
tax-exempt accounts will have tax withheld by the Canadian government on the
entire distribution, including the return of capital and return on capital
portions. The Notice is effective January 1, 2005.

On September 17, 2003 Canadian unitholders
approved an amendment to the Trust's Trust Indenture providing that residency
restriction provisions need not be enforced while the Trust continues to qualify
as a Mutual Fund Trust under Canadian tax legislation.

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.

Related party

Property sale

On December 30, 2004, at the conclusion of a
competitive process, Provident sold properties to a private company on whose
board two of the directors of Provident sit and in which they own shares. The
properties were sold for consideration of $3.5 million of which $0.5 million was
cash and $3.0 million consisted of 10,000,000 common shares valued at $0.30 per
share. The carrying value of these shares are included in investments on the
balance sheet. The transaction was recorded at fair value.

Management internalization

On January 17, 2003, unitholders of the Trust
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 managements' interests with
those of unitholders.

Business prospects

Provident intends to execute a balanced portfolio strategy. In
the COGP business internal development projects with a board approved capital
budget of $68.8 million are planned.

- 56 -

---



Acquisitions of interest in properties close
to properties already owned or partially owned by Provident will be pursued. In
the USOGP business internal development projects are planned with a board
approved capital budget of $ 41.1 million. 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.

Sensitivities

The following table shows the estimated sensitivity of 2005 cash flows to
changes in pricing, interest and volume with the assets and hedge positions in
place:

|                             | Change
|---------------------------- | ------
|                             |       
|Pricing                      |       
|WTI
    (+US$ 1.00) Oil      | $     
|AECO (+Cdn$ 0.25) Gas        | $     
|Interest (+/-1.0%)           | $     
|US exchange (+Cdn$
    0.01) | $     
|Volume (000s)                |       
|Light/Medium Oil (+100 bpd)  | $     
|Heavy Oil (+100 bpd)         | $     
|Natural Gas (+1.0
    mmcfd) | $     

Critical accounting policies

Provident's accounting policies are described
in note 2 to the consolidated financial statements. Certain accounting policies
are identified as critical accounting policies because they form an integral
part of Provident's financial position. And also require management to make
judgments and estimates based on conditions and assumptions that are inherently
uncertain. These accounting policies could result in materially different
results should the underlying assumptions or conditions change.

Management assumptions are based on
Provident's historical experience, management's experience, and other factors
that, in management's opinion, are relevant and appropriate. Management
assumptions may change over time, as further experience is gained or as
operating conditions change.

Details of Provident's critical accounting policies are as
follows:

Property, plant and equipment

Provident follows the full cost method of
accounting, whereby all costs associated with the acquisition and development of
oil and natural gas reserves are capitalized. Utilization of the full cost
method of accounting requires the use of management estimates and assumptions
for amounts recorded for depletion and depreciation of property, plant and
equipment as well as for the ceiling test.

- 57 -

---



The provision for depletion and depreciation
is calculated using the unit of production method based on current production
divided by Provident's share of estimated total proved oil and natural gas
reserve volumes before royalties. The recoverability of a cost centre is tested
by comparing the carrying value of the cost centre to the sum of the
undiscounted cash flows expected from the cost centre. If the carrying value is
not recoverable the cost centre is written down to its fair value.

Proved reserves are an estimate, under
existing reserve evaluation polices, of volumes that can reasonably be expected
to be economically recoverable under existing technology and economic
conditions. Changes in underlying assumptions or economic conditions could have
a material impact on Provident's financial results. To mitigate these risks
management utilizes McDaniel & Associates Consultants Ltd., an independent
engineering firm, to evaluate Provident's Canadian reserves. For Provident's
U.S. based assets management utilizes Cawley, Gillespie & Associates, Inc. and
Netherland, Sewell & Associates, Inc., independent engineering firms, to
evaluate reserves.

Estimates of future production, oil and
natural gas prices and future costs used in the ceiling test are, by their very
nature, subject to uncertainty and changes in underlying assumptions could have
a material impact on Provident's financial results.

Asset retirement obligation

Under the asset retirement obligation (ARO)
standard, the fair value of asset retirement obligations is recorded as a
liability on a discounted basis, when incurred. The value of the related assets
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 financial results.

Changes in accounting policies

The following changes in accounting policy were adopted by
Provident in 2004.

Convertible debentures

Effective December 31, 2004, the Trust
retroactively adopted the revised CICA Handbook Section 3860 ("HB 3860"),
"Financial Instruments - presentation and disclosure" for financial instruments
that may be settled at the issuer's option in cash or its own equity. The
revised standard requires the Trust to classify proceeds from convertible
debentures issued in 2002, 2003 and 2004 as either debt or equity based on fair
value measurement and the substance of the contractual arrangement. The Trust
previously presented the convertible debenture proceeds (net of financing costs)
and related interest obligations as equity on the consolidated balance sheet on
the basis that the Trust could settle its obligations in exchange for trust
units.

- 58 -

---



The Trust's obligation to make scheduled
payments of principal and interest constitutes a financial liability under the
revised standard and exists until the instrument is either converted or
redeemed. The holders' option to convert the financial liability into trust
units is an embedded conversion option. The financial statement effect of this
accounting treatment is outlined in this management's discussion and analysis in
the section entitled interest expense.

Hedging relationships

Effective January 1, 2004 the Trust adopted
CICA accounting guideline 13, "Hedging relationships." 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. Any derivative financial
instruments that do not meet the hedging criteria will be accounted for in
accordance with Emerging Issues Committee ("EIC") - 128, "Accounting for
Trading, Speculative or Non-Hedging Derivative Financial Instruments." These
instruments will be recorded on the balance sheet at fair value and changes in
fair value will be recognized in income in the period in which the change
occurs. In connection with the implementation of accounting guideline 13 the
Trust reviewed its Commodity Price Risk Management Program and determined that
none of the derivative instruments qualified for hedge accounting.

At January 1, 2004 the Trust recorded an
unrealized loss of $25.1 million in deferred charges on the Consolidated Balance
Sheet that is being recognized in income over the term of the previously
designated hedged items. The earnings impact was a $23.0 million loss before
income taxes for the year ended December 31, 2004 recorded in unrealized loss on
non-hedging derivative instruments on the Statement of Operations and
Accumulated Loss.

At December 31, 2004 the Trust recorded a non-hedging
derivative instrument payable of $24.5 million, being the mark to market loss
position of the Trust's non-hedging derivative instruments at that date. As a
result, the Trust recorded a loss on non-hedging derivative instruments of $0.6
million for the year ended December 31, 2004.

Full cost accounting

Effective January 1, 2004 the Trust adopted
CICA accounting guideline 16, "Oil and Gas Accounting - Full Cost." This
accounting guideline replaced CICA accounting guideline 5, "Full cost accounting
in the oil and gas industry." Accounting guideline 16 modifies how the ceiling
test calculation is performed. The recoverability of a cost centre is tested by
comparing the carrying value of the cost centre to the sum of the undiscounted
cash flows expected from the cost centre. If the carrying value is not
recoverable the cost centre is written down to its fair value. Adopting
accounting guideline 16 had no effect on the Trust's financial results.

- 59 -

---



Unit based compensation

Provident accounts for the unit option plan using the fair value of the
option at the date of issue. Under the fair value method the amount to be
recognized as expense is determined at the time the options are issued and is
deferred and recognized in earnings over the vesting period of the options with
a corresponding increase in contributed surplus. This method was adopted in
2003. For the period from December 2003 to November 2004 the Trust used the
intrinsic method to estimate the compensation expense associated with the unit
option plan. The intrinsic value method re-valued unexercised options based on
the trading price of the trust's trust units at the balance sheet date and
amortized any change in value over the remaining vesting period of the
unexercised options. As the change in methodology in 2004 is a change in
estimate under accounting standards, the fair value methodology has been applied
prospectively without restatement of prior periods.

Foreign currency translation

In the fourth quarter of 2004, the Trust
reviewed its practices for U.S. operations and determined that such operations
are self-sustaining as a result of the development of the Trust's management
practices for U.S. operations. The accounts of self-sustaining foreign
operations are translated using the current rate method, whereby assets and
liabilities are translated at period-end exchange rates, while revenues and
expenses are translated using rates for the period. Translation gains and losses
related to the operations are deferred and included as a separate component of unitholder's equity. Previously, operations outside of Canada were considered to
be integrated and translated using the temporal method. Under the temporal
method, monetary assets and liabilities were translated at the period end
exchange rates, other assets and liabilities at the historical rates and
revenues and expenses at the rates for the period except depreciation, depletion
and accretion, which were translated on the same basis as the related assets.
This change in practice was adopted prospectively beginning October 1, 2004.

Transportation

Transportation costs incurred on Canadian oil and gas
operations have been classified as expenses in 2004. Comparative balances have
been restated

Recent accounting pronouncements

The following new accounting guidelines or standards are
applicable to Provident but have not been implemented.

Variable interest entities ("VIEs")

In June 2003 the CICA issued Accounting
Guideline 15 ("AcG-15") "Consolidation of Variable Interest Entities". AcG-15
defines VIEs as entities in which either; the equity at risk is not sufficient
to permit that entity to finance its activities without additional financial
support from other parties; or equity investors lack voting control, an
obligation to absorb expected losses or the right to receive expected residual
returns. AcG-15 harmonizes Canadian and U.S. GAAP and provides guidance for
companies consolidating VIEs in which they are the primary beneficiary. The
guideline is effective

- 60 -

---



for all annual and interim periods beginning on or after
November 1, 2004. Provident does not expect this guideline to have a material
impact on the Trust.

Exchangeable shares

The CICA has issued an amendment to an EIC, "Income trusts
-
exchangeable shares." The Trust has not evaluated the effect that this standard
might have on the consolidated financial statements.

Business risks

The 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:

- fluctuations in commodity price, exchange rates and
  interest rates;
- government and regulatory risk in respect of royalty and
  income tax regimes;
- operational risks that may affect the quality and
  recoverability of reserves;
- geological risk associated with accessing and recovering
  new quantities of reserves;
- transportation risk in respect of the ability to transport
  oil and natural gas to market; 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:

- 



Provident strives to minimize these business risks by:

- 

- 61 -

---



- 



Unit trading activity

The following table summarizes the unit trading activity of
the Provident units for the four quarters ended December 31, 2004 on both the
Toronto Stock Exchange and the American Stock Exchange:

|                    |   | Q1 |        |   | Q2 |        |   | Q3 |        |   | Q4 |       
|------------------- | - | -- | ------ | - | -- | ------ | - | -- | ------ | - | -- | ------
|TSE - PVE.UN (Cdn$) |   |    |        |   |    |        |   |    |        |   |    |       
|High                | $ |    | 11.55  | $ |    | 11.77  | $ |    | 11.43  | $ |    | 11.96 
|Low                 | $ |    | 9.21   | $ |    | 10.29  | $ |    | 10.19  | $ |    | 10.56 
|Clos e              | $ |    | 10.76  | $ |    | 10.29  | $ |    | 11.20  | $ |    | 11.37 
|Volume (000s)       |   |    | 13,156 |   |    | 25,275 |   |    | 26,858 |   |    | 21,851
|AMEX - PVX (US$)    |   |    |        |   |    |        |   |    |        |   |    |       
|High                | $ |    | 9.06   | $ |    | 8.74   | $ |    | 8.96   | $ |    | 9.61  
|Low                 | $ |    | 7.59   | $ |    | 7.63   | $ |    | 7.70   | $ |    | 8.49  
|Close               | $ |    | 8.24   | $ |    | 7.71   | $ |    | 8.88   | $ |    | 9.48  
|Volume (000s)       |   |    | 36,172 |   |    | 48,255 |   |    | 50,024 |   |    | 62,211

- 62 -

---

Quarterly table

|                                       | 2004
|-------------------------------------- | ----
|                                       |     
|($000s except per unit
    amounts)    |     
|Financial -
    consolidated           |     
|Revenue                                | $   
|Cash flow                              | $   
|Net income (loss)                      | $   
|Unitholder distributions               | $   
|Distributions per unit                 | $   
|                                       |     
|Oil and gas production                 |     
|Cash revenue                           | $   
|Earnings before interest, DD&A, taxes  | $   
|and other non-cash items               |     
|Cash flow                              | $   
|Net income (loss)                      | $   
|                                       |     
|Midstream services and
    marketing   |     
|Cash revenue                           | $   
|Earnings before
    interest, DD&A and | $   
|taxes                                  |     
|Cash flow                              | $   
|Net income                             | $   
|                                       |     
|Operating                              |     
|Oil and gas production                 |     
|Light/medium oil (bpd)                 |     
|Heavy oil (bpd)                        |     
|Natural gas liquids (bpd)              |     
|Natural gas (mcfd)                     |     
|Oil equivalent (boed)                  |     
|                                       |     
|Midstream services and
    marketing   |     
|Redwater throughput (bpd)              |     
|                                       |     
|(Cdn $)                                |     
|Average selling price
    net of       |     
|transportation expense                 |     
|Light/medium oil per bbl               |     
|(before hedges)                        | $   
|Light/medium oil per bbl               |     
|(including hedges)                     | $   
|Heavy oil per bbl                      |     
|(before hedges)                        | $   
|Heavy oil per bbl                      |     
|(including hedges)                     | $   
|Natural gas liquids per barrel         | $   
|Natural gas per mcf                    |     
|(before hedges)                        | $   
|Natural gas per mcf                    |     
|(including hedges)                     | $   

(1)

- 63 -

---



Quarterly table

|                                                        | 2003 (1)
|------------------------------------------------------- | --------
|                                                        |         
|($000s except per unit
    amounts)                     |         
|Financial -
    consolidated                            |         
|Revenue                                                 | $       
|Cash flow                                               | $       
|Net income                                              | $       
|Unitholder distributions                                | $       
|Distributions per unit                                  | $       
|                                                        |         
|Oil and gas production                                  |         
|Cash revenue                                            | $       
|Earnings before
    interest, DD&A and                  |         
|taxes                                                   | $       
|Cash flow                                               | $       
|Net income                                              | $       
|                                                        |         
|Midstream services and
    marketing                    |         
|Cash revenue                                            | $       
|Earnings before
    interest, DD&A and                  |         
|taxes                                                   | $       
|Cash flow                                               | $       
|Net income                                              | $       
|                                                        |         
|Operating                                               |         
|Oil and gas production                                  |         
|Light/medium oil (bpd)                                  |         
|Heavy oil (bpd)                                         |         
|Natural gas liquids (bpd)                               |         
|Natural gas (mcfd)                                      |         
|Oil equivalent (boed)                                   |         
|                                                        |         
|Midstream services and
    marketing                    |         
|Redwater throughput
    (bpd)                           |         
|                                                        |         
|(Cdn $ per boe)                                         |         
|Average selling price
    net of transportation expense |         
|Light/medium oil per bbl                                |         
|(before hedges)                                         | $       
|Light/medium oil per bbl                                |         
|(including hedges)                                      | $       
|Heavy oil per bbl                                       |         
|(before hedges)                                         | $       
|Heavy oil per bbl                                       |         
|(including hedges)                                      | $       
|Natural gas liquids per barrel                          | $       
|Natural gas per mcf                                     |         
|(before hedges)                                         | $       
|Natural gas per mcf                                     |         
|(including hedges)                                      | $       

- 64 -

---



AUDITORS' REPORT

To the Unitholders of Provident Energy Trust

We have audited the consolidated balance sheets of Provident Energy Trust as
at December 31, 2004 and 2003 and the consolidated statements of operations and
accumulated loss and cash flows for the years ended December 31, 2004 and 2003.
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 from
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,
2004 and 2003, and the results of its operations and cash flows for the years
ended December 31, 2004 and 2003, in accordance with Canadian generally accepted
accounting principles.



|PricewaterhouseCoopers
    LLP | Calgary, Alberta
|------------------------------ | ----------------
|Chartered Accountants          | March 9, 2005   

Comments by Auditor for U.S. readers on Canada-U.S. reporting differences

In the United States, reporting standards for auditors require the addition
of an explanatory paragraph (following the opinion paragraph) when there is
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 9, 2005 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.



|PricewaterhouseCoopers
    LLP | Calgary, Alberta
|------------------------------ | ----------------
|Chartered Accountants          | March 9, 2005   

---





PROVIDENT ENERGY TRUST

CONSOLIDATED BALANCE SHEETS

Canadian Dollars (000s)

|                                                       |   | As at        |                   | As at       
|------------------------------------------------------ | - | ------------ | ----------------- | ------------
|                                                       |   | December 31, |                   | December 31,
|                                                       |   | 2004         |                   | 2003        
|                                                       |   |              | (restated note 3)
|Assets                                                 |   |              |                   |             
|Current assets                                         |   |              |                   |             
|Cash                                                   | $ | 244          | $                 | 45          
|Accounts receivable                                    |   | 143,142      |                   | 118,890     
|Petroleum product inventory                            |   | 17,151       |                   | 24,206      
|Deferred derivative loss (notes 2, 3 and 15)           |   | 2,144        |                   | -           
|Prepaid expenses                                       |   | 10,265       |                   | 5,632       
|                                                       |   | 172,946      |                   | 148,773     
|Cash reserve for future site reclamation
    (note 16) |   | 1,454        |                   | 1,829       
|Investments (note 2 and 13)                            |   | 3,000        |                   | -           
|Deferred financing charges (note 3)                    |   | 5,584        |                   | 5,019       
|Property, plant and equipment (note 5)                 |   | 1,299,654    |                   | 884,891     
|Goodwill (note 4)                                      |   | 330,944      |                   | 102,443     
|                                                       | $ | 1,813,582    | $                 | 1,142,955   
|Liabilities                                            |   |              |                   |             
|Current liabilities                                    |   |              |                   |             
|Accounts payable and accrued liabilities               | $ | 171,412      | $                 | 121,832     
|Cash distributions payable                             |   | 15,416       |                   | 8,389       
|Distribution payable to non-controlling
    interest   |   | 271          |                   | -           
|Financial derivative instruments (notes 2 and
    3)   |   | 24,524       |                   | -           
|                                                       |   | 211,623      |                   | 130,221     
|Long-term debt (note 3 and 6)                          |   | 432,206      |                   | 356,573     
|Asset retirement obligation (notes 2 and 8)            |   | 40,506       |                   | 33,182      
|Future income taxes (note 12)                          |   | 70,629       |                   | 58,805      
|                                                       |   |              |                   |             
|Non-controlling interest                               |   | 13,649       |                   | -           
|                                                       |   |              |                   |             
|Unitholders' Equity                                    |   |              |                   |             
|Unitholders' contributions (note 9)                    |   | 1,438,393    |                   | 803,299     
|Exchangeable shares (note 9)                           |   | 34,439       |                   | 19,518      
|Convertible debentures equity component (note
    3)   |   | 9,785        |                   | 7,908       
|Contributed surplus (note 10)                          |   | 2,002        |                   | 1,305       
|Cumulative translation adjustment (note 3)             |   | (28,848)     |                   | -           
|Accumulated income (loss)                              |   | 1,844        |                   | (19,838)    
|Accumulated cash distributions (note 11)               |   | (412,646)    |                   | (248,018)   
|                                                       |   | 1,044,969    |                   | 564,174     
|                                                       | $ | 1,813,582    | $                 | 1,142,955   



|Approved by the
    Board of Directors of Provident Energy Ltd. |                                
|--------------------------------------------------------------- | -------------------------------
|                                                                |                                
|(Signed) Grant D.
    Billing                                   | (Signed) M.H.
    (Mike) Shaikh
|Director                                                        | Director                       
|                                                                |                                
|- 1 -                                                          

---



PROVIDENT ENERGY TRUST

CONSOLIDATED STATEMENT OF OPERATIONS AND ACCUMULATED INCOME (LOSS)

Canadian Dollars (000s except per unit amounts)

|                                                    |   |              |                   |         
|--------------------------------------------------- | - | ------------ | ----------------- | --------
|                                                    |   | Year ended   |                  
|                                                    |   | December 31, |                  
|                                                    |   | 2004         |                   | 2003    
|                                                    |   |              | (restated note 3)
|Revenue(note
    7)                                 |   |              |                   |         
|Revenue                                             | $ | 1,200,854    | $                 | 455,263 
|Realized loss on financial derivative instruments   |   | (68,944)     |                   | (48,934)
|Unrealized loss on financial derivative instruments |   | (22,053)     |                   | -       
|                                                    |   | 1,109,857    |                   | 406,329 
|                                                    |   |              |                   |         
|Expenses                                            |   |              |                   |         
|Cost of goods sold                                  |   | 741,641      |                   | 153,147 
|Production, operating and maintenance               |   | 141,493      |                   | 84,040  
|Transportation                                      |   | 5,087        |                   | 5,447   
|General and administrative                          |   | 27,104       |                   | 15,365  
|Non-cash general and adminstrative (note 10)        |   | 1,819        |                   | 1,305   
|Management internalization (note 13)                |   | -            |                   | 18,592  
|Interest on bank debt                               |   | 11,816       |                   | 9,733   
|Interest, accretion and amortization on convertible |   |              |                   |         
|debentures                                          |   | 16,608       |                   | 9,955   
|Foreign exchange (gains) losses                     |   | (2,224)      |                   | 180     
|Depletion, depreciation and accretion               |   | 177,282      |                   | 138,272 
|                                                    |   | 1,120,626    |                   | 436,036 
|                                                    |   |              |                   |         
|Loss before taxes                                   |   | (10,769)     |                   | (29,707)
|                                                    |   |              |                   |         
|Capital taxes                                       |   | 5,921        |                   | 3,332   
|Current and
    withholding taxes                   |   | 1,282        |                   | -       
|Future income tax
    recovery (note 12)            |   | (40,577)     |                   | (56,478)
|                                                    |   | (33,374)     |                   | (53,146)
|                                                    |   |              |                   |         
|Net income before
    non-controlling interest      |   | 22,605       |                   | 23,439  
|Non-controlling
    interest                        |   | 923          |                   | -       
|Net income                                          |   | 21,682       |                   | 23,439  
|                                                    |   |              |                   |         
|Accumulated loss,
    beginning of year             |   | (4,029)      |                   | (37,423)
|Retroactive
    application of changes in           |   |              |                   |         
|accounting policies (Note 3)                        |   | (15,809)     |                   | (5,854) 
|Accumulated loss,
    beginning of year, restated   |   | (19,838)     |                   | (43,277)
|Accumulated income
    (loss), end of year          | $ | 1,844        | $                 | (19,838)
|                                                    |   |              |                   |         
|Net earnings per unit
    - basic                   | $ | 0.19         | $                 | 0.34    
|- diluted                                           | $ | 0.19         | $                 | 0.34    





-2-

---





|PROVIDENT ENERGY TRUST                                                     
|---------------------------------------------------------------------------
|CONSOLIDATED STATEMENT OF CASH FLOWS
    (000s) Canadian dollars           
|                                                                           
|                                                                           
|                                                                           
|                                                                           
|                                                                           
|                                                                           
|                                                                           
|Cash provided by
    operating activities                                  
|Net income for the year                                                    
|Add non-cash items:                                                        
|Depletion, depreciation and accretion                                      
|Amortization of deferred charges                                           
|Debenture accretion and amortization of deferred financing charges (note 6)
|                                                                           
|Non-cash general and administrative (note 10)                              
|Unrealized loss on non-hedging derivative instruments (note 7)             
|Unrealized foreign exchange gain                                           
|                                                                           
|Future income tax recovery                                                 
|Non-controlling interest (note 4)                                          
|Management internalization (note 13)                                       
|Cash flow from operations before changes in working capital                
|and site restoration expenditures                                          
|                                                                           
|Site restoration expenditures                                              
|Change in non-cash operating working capital                               
|                                                                           
|                                                                           
|Cash used for
    financing activities                                     
|Proceeds (repayments) of long-term debt                                    
|Proceeds of bridge financing                                               
|Repayment of bridge financing                                              
|Declared distributions to unitholders                                      
|Declared distributions to non-controlling interest                         
|Issue of trust units, net of issue costs                                   
|Issue of debenture, net of costs                                           
|Change in non-cash financing working capital                               
|                                                                           
|                                                                           
|Cash used for
    investing activities                                     
|Expenditures on property, plant and equipment                              
|Acquisition of Olympia Energy Inc. (note 4)                                
|Acquisition of Viracocha Energy Inc. (note 4)                              
|Acquisition of Breitburn Energy LLC (note 4)                               
|Acquisition of Redwater (note 4)                                           
|Oil and gas property acquisitions                                          
|Acquisition of Provident Management Corp                                   
|Proceeds on disposition of oil and natural gas properties                  
|Reclamation fund contributions                                             
|Reclamation fund withdrawals                                               
|Payment of non-hedging derivative instruments                              
|Reimbursement for leasehold improvements                                   
|Change in non-cash investing working capital                               
|                                                                           
|                                                                           
|Increase in cash                                                           
|Cash beginning
    of year                                                 
|Cash end of year                                                           
|                                                                           
|                                                                           
|Supplemental
    disclosure of cash flow information                       
|Cash interest
    paid including debenture interest                        





-3-

---





NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

(Tabular amounts in Cdn$ 000's, except unit and per unit amounts)

December 31, 2004

1.

> Provident Energy Trust (the "Trust") is an open-end unincorporated
>   investment trust created under the laws of Alberta pursuant to a trust
>   indenture dated January 25, 2001, amended from time to time. The beneficiaries
>   of the Trust are the unitholders. The Trust was established to hold, directly
>   and indirectly all types of petroleum and natural gas and energy related
>   assets, including without limitation facilities of any kind, oil sands
>   interests, electricity or power generating assets and pipeline, gathering,
>   processing and transportation assets. The Trust commenced operations March 6,
>   2001. Cash flow is provided to the Trust from properties owned and operated by
>   Provident Energy Ltd. and directly and indirectly owned subsidiaries 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.

> (i)

> The consolidated financial statements include the
>     accounts of the Trust and Provident and its subsidiary Breitburn Energy Ltd.
>     (Breitburn), and are presented in accordance with Canadian generally
>     accounting principles.
>     The Trust has an investment in a private company
>     representing 20 percent of the total outstanding private company's shares.
>     The Trust does not have direct or joint control over the strategic
>     operating, investing and financing decisions of the private company, but
>     does have significant influence. The investment in the private company is
>     accounted for using the equity method.

(ii)

> All derivative financial instruments are recorded on the
>     balance sheet at fair value and changes in fair value are recognized in
>     income as unrealized gains (losses) on financial derivative instruments in
>     the period in which the change occurs. Actual gains (losses) are recorded as
>     realized gains (losses) on financial derivative instruments in the period
>     that the instrument is settled.

(iii)

> The Trust follows the full cost method of accounting for
>     oil and natural gas exploration and development activities, whereby all
>     costs associated with the acquisition and development of oil and natural gas
>     reserves are capitalized. Such costs include lease acquisition, lease
>     rentals on non-producing properties, geological and geophysical activities,
>     drilling of productive and non-productive wells, and tangible well
>     equipment. Gains or losses on the disposition of oil and gas properties are
>     not recognized unless the resulting change to the depletion and depreciation
>     rate is 20 percent or more. 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.

-4-

---

a)
    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.

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.

b)

> Effective January 1, 2004 the ceiling test calculation
>       is performed by comparing the carrying value of the cost centre to the sum
>       of the undiscounted proved reserve cash flows expected from the cost
>       centre using future price estimates. If the carrying value is not
>       recoverable, the cost centre is written down to its fair value. Fair value
>       is determined by the future cash flows from the proved plus probable
>       reserves discounted at the Trust's risk free interest rate. Any excess
>       carrying value of the assets on the balance sheet above fair value would
>       be recorded in depletion, depreciation and accretion expense as a
>       permanent impairment.

> (iv)

> Provident conducts many of its oil and gas production activities through
>     joint ventures and the accounts reflect only Provident's proportionate
>     interest in such activities.

(v)

> Inventories of products are valued at the lower of average cost and net
>     realizable value based on quoted market prices.

(vi)

> Goodwill, which represents the excess of the cost of an
>     acquired enterprise over the net of the amounts assigned to assets acquired
>     and liabilities assumed, is assessed at least annually for impairment. To
>     assess impairment, the fair value of the reporting unit is determined and
>     compared to the book value of the reporting unit. If the fair value is less
>     than the book value, then a second test is performed to determine the amount
>     of the impairment. The amount of the impairment is determined by deducting
>     the fair value of the reporting unit's assets and liabilities from the fair
>     value of the reporting unit to determine the implied fair value of goodwill
>     and comparing that amount to the book value of the reporting unit's
>     goodwill. Any excess of the book value of goodwill over the implied fair
>     value of goodwill is the impaired amount. Goodwill is not amortized

(vii)

> Under the asset retirement obligation ("ARO") standard
>     the fair value of a liability for an ARO is recorded in the period where a
>     reasonable estimate of the fair value can be determined. When the liability
>     is recorded, the carrying amount of the related asset is increased by the
>     same amount of the liability. The asset recorded is depleted over the useful
>     life of the asset. Additions to asset retirement obligations due to the
>     passage of time are recorded as accretion expense. Actual expenditures
>     incurred are charged against the obligation.

-5-

---

(viii)
  Unit option
  plan

> The Trust uses the fair value method for valuing
>     compensation expense associated with the Trust's unit option plan ("the
>     Plan"). Provident has applied this method to options issued after January 1,
>     2003, the effective date for implementing stock based compensation
>     accounting. Under the fair value method the amount to be recognized as
>     expense is determined at the time the options are issued and is deferred and
>     recognized in earnings over the vesting period of the options with a
>     corresponding increase in contributed surplus.

(ix)

> The Trust has established a unit appreciation rights plan
>     (UAR's) for certain employees of its U.S. subsidiary. Liabilities under the
>     Trust's UAR's are estimated at each balance sheet date, based on the amount
>     of UAR's that are in the money using the unit price as at that date.
>     Expenses are recorded through non-cash general and administrative costs,
>     with an offsetting amount in accounts payable.

(x)

> The Trust applies the treasury stock method to determine
>     the dilutive effect of trust unit rights and trust unit options. Under the
>     treasury stock method, outstanding and exercisable instruments that will
>     have a dilutive effect are included in per unit diluted calculations,
>     ordered from most dilutive to least dilutive.
>     The dilutive effect of convertible debentures is
>     determined using the "if-converted" method whereby if the current market
>     price per unit is in excess of the stated conversion price per unit the
>     weighted-average number of potential units assumed issued are included in
>     the per unit - diluted calculations. The units issued upon conversion are
>     included in the denominator of per unit - basic calculations from the date
>     of conversion. Consequently, units assumed issued are weighted for the
>     period the convertible debentures were outstanding, and units actually
>     issued are weighted for the period the units were outstanding.

(xi)

> Provident follows the liability method for calculating
>     income taxes. Differences between the amounts reported in the financial
>     statements of the corporate subsidiaries and their respective tax bases are
>     applied to tax rates in effect to calculate the future tax liability. The
>     effect of any change in income tax rates is recognized in the current period
>     income.

The Trust is a taxable entity under the Income Tax Act
    (Canada) and is 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.

(xii)

> Revenues 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

-6-

---

services are provided. Revenues associated with the sale of natural gas
    liquids storage services are recognized when the services are provided.
  (xiii)
  Use of
  estimates

> The preparation of financial statements requires
>     management to make estimates based on currently available information. In
>     particular, management makes estimates for amounts recorded for depletion
>     and depreciation of the property, plant and equipment, and asset retirement
>     obligation. The ceiling test uses factors such as estimated reserves,
>     production rates, estimated future petroleum and natural gas prices and
>     future costs. Due to the inherent limitations in metering and the physical
>     properties of storage caverns the determination of precise volumes of
>     natural gas liquids held in inventory at such locations is subject to
>     estimation. Actual inventories of natural gas liquids can only be determined
>     by draining of the caverns. By their very nature, these estimates are
>     subject to measurement uncertainty and the effect on the financial
>     statements of future periods could be material.
>     The estimation of oil and gas reserves is a subjective
>     process. Forecasts are based on engineering data, projected future rates of
>     production, estimated commodity prices, and consider the timing of future
>     expenditures. The Trust expects reserve estimates to be revised based on the
>     results of future drilling activity, testing, production levels, and
>     economics of recovery based on cash flow forecasts.

3.

> (i)

> Effective January 1, 2004 the Trust adopted CICA
>     accounting guideline 13, "Hedging relationships."

At January 1, 2004 the Trust recorded an unrealized loss
    of $25.1 million in deferred charges on the consolidated balance sheet that
    is being recognized in income over the term of the previously designated
    hedged items. For the period ending December 31, 2004, $23.0 million of this
    deferred charge has been amortized.

At December 31, 2004 the Trust recorded a financial derivative instrument
    payable of $24.5 million, that being the mark to market loss position of the
    Trust's financial derivative instruments at that date.

(ii)

> Effective January 1, 2004 the Trust adopted CICA
>     accounting guideline 16, "Oil and Gas Accounting - Full Cost." This
>     accounting guideline replaced CICA accounting guideline 5, "Full Cost
>     Accounting in the Oil and Gas Industry." Accounting guideline 16 modifies
>     how the ceiling test calculation is performed. The recoverability of a cost
>     centre is tested by comparing the carrying value of the cost centre to the
>     sum of the undiscounted proved reserve cash flows expected from the cost
>     centre using future price estimates. If the carrying value is not
>     recoverable, the cost centre is written down to its

-7-

---



> fair value determined by comparing the future cash flows
>     from the proved plus probable reserves discounted at the Trust's risk free
>     interest rate. Any excess carrying value of the assets on the balance sheet
>     above fair value would be recorded in depletion, depreciation and accretion
>     expense as a permanent impairment. Adopting accounting guideline 16 had no
>     effect on the Trust's financial results.
>   (iii)

> Effective December 31, 2004, the Trust retroactively
>     adopted the revised CICA Handbook Section 3860 ("HB 3860"), "Financial
>     Instruments - Presentation and Disclosure" for financial instruments that
>     may be settled at the issuer's option in cash or its own equity. The revised
>     standard requires the Trust to classify proceeds from convertible debentures
>     issued in 2002, 2003 and 2004 as either debt or equity based on fair value
>     measurement and the substance of the contractual arrangement. The Trust
>     previously presented the convertible debenture proceeds (net of financing
>     costs) and related interest obligations as equity on the consolidated
>     balance sheet on the basis that the Trust could settle its obligations in
>     exchange for trust units. Issue costs on convertible debentures are recorded
>     as deferred financing charges and are amortized over the life of the
>     debenture.
>     The Trust's obligation to make scheduled payments of
>     principal and interest constitutes a financial liability under the revised
>     standard and exists until the instrument is either converted or redeemed.
>     The holders' option to convert the financial liability into trust units is
>     an embedded conversion option. The effect of the adoption of this standard
>     is presented in Note 6 to the financial statements.

(iv)

> In the fourth quarter of 2004, the Trust reviewed its
>     practices for U.S. operations and determined that such operations are
>     self-sustaining as a result of the development of the Trust's management
>     practices for U.S. operations. The accounts of self-sustaining foreign
>     operations are translated using the current rate method, whereby assets and
>     liabilities are translated at period-end exchange rates, while revenues and
>     expenses are translated using rates for the period. Translation gains and
>     losses related to the operations are deferred and included as a separate
>     component of unitholder's equity. Previously, operations outside of Canada
>     were considered to be integrated and translated using the temporal method.
>     Under the temporal method, monetary assets and liabilities were translated
>     at the period end exchange rates, other assets and liabilities at the
>     historical rates and revenues and expenses at the rates for the period
>     except depreciation, depletion and accretion, which were translated on the
>     same basis as the related assets. This change in practice was adopted
>     prospectively beginning October 1, 2004.

(v)

> Transportation costs incurred on Canadian oil and gas operations have
>     been classified as expenses in 2004. Comparative balances have been
>     restated.

-8-

---

4.Acquisitions

> (i)

> On June 1, 2004 Provident acquired Olympia Energy Inc.
>     for consideration of 13,385,579 Trust units with an ascribed value of $152.9
>     million and 1,325,000 exchangeable shares with an ascribed value of $15.1
>     million plus acquisition costs which when netted with option proceeds total
>     $4.7 million. Olympia was a public oil and gas exploration and production
>     company active in the Western Canadian sedimentary basin. The transaction
>     has been accounted for using the purchase method with the allocation of the
>     purchase price as follows:

|Net assets
        acquired and liabilities assumed |   |         
|--------------------------------------------------- | - | --------
|Property, plant and equipment                       | $ | 162,352 
|Goodwill                                            |   | 106,499 
|Working capital deficiency                          |   | (326)   
|Bank debt                                           |   | (53,852)
|Asset retirement obligation                         |   | (1,909) 
|Non-hedging derivative instrument                   |   | (947)   
|Future income taxes                                 |   | (39,107)
|                                                    | $ | 172,710 
|                                                    |   |         
|Consideration                                       |   |         
|Acquisition costs                                   | $ | 8,700   
|Option proceeds                                     |   | (3,985) 
|Exchangeable shares issued (note 9)                 |   | 15,132  
|Trust units issued (note 9)                         |   | 152,863 
|                                                    | $ | 172,710 

(ii)

> On June 1, 2004 Provident acquired Viracocha Energy Inc.
>     for consideration of 12,758,386 Trust units with an ascribed value of $145.7
>     million and 1,325,000 exchangeable shares with an ascribed value of $15.1
>     million and acquisition costs

- 9 -

---



> Net assets
>         acquired and liabilities assumedProperty, plant
>         and equipment
>         $
>         109,907Goodwill
>         
>         122,002Working capital
>         
>         2,172Bank debt
>         
>         (49,891)Capital lease
>         obligation
>         
>         (77)Deferred lease
>         obligation
>         
>         (98)Asset retirement
>         obligation
>         
>         (7,895)Future income
>         taxes
>         
>         (13,294)$
>         162,826ConsiderationAcquisition costs
>         $
>         9,000Option and warrant
>         proceeds
>         
>         (7,007)Exchangeable
>         shares issued (note 9)
>         
>         15,132Trust units issued
>         (note 9)
>         
>         145,701$
>         162,826

> (iii)

> On June 15, 2004 Provident acquired 92 percent of
>     Breitburn Energy LLC (Breitburn) for consideration of $157.4 million and
>     acquisition costs of $8.2 million. Breitburn is a private company (now a
>     limited partnership) active in the oil and gas exploitation and production
>     business in the Los Angeles basin, USA. The transaction has been accounted
>     for using the purchase method with the allocation of the purchase price as
>     follows

|Net assets
        acquired and liabilities assumed |   |         
|--------------------------------------------------- | - | --------
|Property, plant and equipment                       | $ | 214,261 
|Working capital deficiency                          |   | (8,402) 
|Non-hedging derivative instruments                  |   | (25,181)
|Other assets                                        |   | 1,028   
|Asset retirement obligation                         |   | (2,367) 
|Non-controlling interest                            |   | (13,690)
|                                                    | $ | 165,649 
|                                                    |   |         
|Consideration                                       |   |         
|Acquisition costs                                   | $ | 8,214   
|Cash                                                |   | 157,435 
|                                                    | $ | 165,649 

> On October 4, 2004, the Trust funded Breitburn $58.5
>     million (US $45 million) for the Orcutt property acquisition. The result of
>     this funding increased Provident's ownership interest in Breitburn by 2.2
>     percent to a total of 94.2 percent.
>   (iv)

> 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

- 10 -

---

from the issuance of 19,205,000 trust units. In 2004 an additional $1.3
    million of acquisition costs were incurred and allocated to property, plant
    and equipment and financed by long-term debt.

Provident allocated the purchase price of Redwater as follows:

|Net assets
        acquired                                                     |   |        
|------------------------------------------------------------------------------- | - | -------
|Petroleum product inventory                                                     | $ | 15,413 
|Property, plant and equipment (includes acquisition costs of $6,763)            |   | 283,225
|                                                                                | $ | 298,638
|The
        acquisition was financed by:                                        |   |        
|Revolving
        term credit facility (note 6)                                 | $ | 35,768 
|Issuance of
        trust units issued for cash (net of costs $10,582) (note 9) |   | 191,070
|Issuance of
        convertible debentures (net of costs of $3,205) (note 6)    |   | 71,800 
|                                                                                | $ | 298,638

5.

> Accumulateddepletion and
>         
>         Net
>         BookDecember 31, 2004
>         
>         Cost
>         
>         depreciation
>         
>         valueOil and natural gas properties
>         $
>         1,567,902
>         $
>         555,280
>         $
>         1,012,622Midstreamassets
>         
>         293,616
>         
>         11,815
>         
>         281,801Office equipment
>         
>         9,904
>         
>         4,673
>         
>         5,231Total
>         $
>         1,871,422
>         $
>         571,768
>         $
>         1,299,654Accumulateddepletion and
>         
>         Net
>         BookDecember 31, 2003
>         
>         Cost
>         
>         depreciation
>         
>         valueOil and natural gas properties
>         $
>         990,568
>         $
>         391,922
>         $
>         598,646Midstreamassets
>         
>         283,225
>         
>         2,206
>         
>         281,019Office equipment
>         
>         8,359
>         
>         3,133
>         
>         5,226Total
>         $
>         1,282,152
>         $
>         397,261
>         $
>         884,891Costs associated with unproved properties excluded from
>   costs subject to depletion as at December 31, 2004 totaled $31.2 million
>   (December 31, 2003 - $16.4 million). Asset retirement costs of $29.4 million
>   are included in the property, plant and equipment (December 31, 2003 - $26.4
>   million).
>   An impairment test calculation was performed on the Trust's
>   property, plant and equipment at December 31, 2004 in which the estimated
>   undiscounted future net cash flows based on estimate future prices associated
>   with the proved reserves exceeded the carrying amount of the Trust's oil and
>   gas property plant and equipment.
>   The following table outlines prices used in the impairment test at December
>   31, 2004:
> Year
>   Oil
>   Gas
>   NGL2005
>   $41.12
>   $ 7.93
>   $37.362006
>   $35.72
>   $ 6.65
>   $29.562007
>   $32.47
>   $ 6.20
>   $25.362008
>   $33.66
>   $ 6.17
>   $25.252009
>   $34.68
>   $ 6.28
>   $24.67

-11-

---

6.Long-term debt

> Dec 31, 2004
>   
>   Dec 31, 2003Revolving term credit facility
>   $
>   262,750
>   
>   $
>   236,500Convertible debentures
>   
>   169,456
>   
>   
>   120,073$
>   432,206
>   
>   $
>   356,573(i)
>   Revolving term credit facilityProvident has a $410 million term credit facility with a
>     syndicate of Canadian chartered banks secured by oil and gas and midstream
>     assets. 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, 2004, the rate was the bank
>     prime of 4.75 percent plus 0.50 percent. At December 31, 2003 the facility
>     totaled $335 million and in February 2004 a credit and consent agreement
>     restricted the borrowing base under the facility to $310 million. In June
>     2004 the facility increased to $370 million and at September 30, 2004, the
>     facility was increased $40 million to its current level of $410 million. The
>     additional $40 million of capacity is intended to provide for a US dollar
>     base rate loan.
>     Pursuant to the terms of the agreement, each year on or
>     after May 24, Provident can request the revolving period to 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 the loan balance due May 2006, one-twelfth due August 2006 and
>     the remaining balance due at the end of the term period. As collateral
>     security, Provident has pledged a $750 million fixed and floating charge
>     debenture against all of its assets.
>     At December 31, 2004 Provident had $31 million in letters
>     of credit outstanding that guarantee Provident's performance under certain
>     commercial contracts associated with the marketing segment of the midstream
>     business unit. At December 31, 2003 Provident's letters of credit totaled
>     $12.3 million.

(ii)

> On July 6, 2004 the Trust issued $50.0 million of
>     unsecured subordinated convertible debentures ($48.0 million net of issue
>     costs) with an 8.0 percent coupon rate maturing July 31, 2009. Issue costs
>     have been classified as deferred financing charges. The debentures may be
>     converted into trust units at the option of the holder at a conversion price
>     of $12.00 per trust unit prior to July 31, 2009, and may be redeemed by the
>     Trust under certain circumstances. The unsecured subordinated convertible
>     debentures were initially recorded fair value of $48.1 million under
>     accounting rules. The difference between the fair value and proceeds of $1.9
>     million was recorded as equity.
>     On September 30, 2003 the Trust issued $75 million of
>     unsecured subordinated convertible debentures ($71.8 million net of issues
>     costs) with an 8.75 percent coupon rate maturing December 31, 2008. Issue
>     costs have been classified as deferred financing charges. 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. The unsecured
>     subordinated convertible debentures were initially recorded at fair value
>     under accounting rules of $70.6 million. The difference between the fair
>     value and proceeds of $4.4 million was recorded as equity.

- 12 -

---



> 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. Issue costs
>     have been classified as deferred financing charges. 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 unsecured subordinated convertible
>     debentures were initially recorded at fair value under accounting rules of
>     $60.6 million. The difference between the fair value and proceeds of $3.8
>     million was recorded as equity.
>     The Trust may elect to satisfy interest and principal
>     obligations by the issuance of trust units. During 2004, $0.12 million of
>     debentures were converted to trust units at the election of debenture
>     holders (2003- $14.35 million).

7.

> Year endedDecember 31,2004
>         
>         2003Gross production
>         revenue
>         $
>         449,869
>         $
>         355,941Product sales and
>         service revenue
>         
>         840,184
>         
>         172,191Royalties
>         
>         (89,199)
>         
>         (72,869)Revenue
>         
>         1,200,854
>         
>         455,263Realized loss on
>         financial derivative instruments
>         
>         (68,944)
>         
>         (48,934)Unrealized loss on
>         financial derivative instruments
>         
>         (22,053)
>         
>         -$
>         1,109,857
>         $
>         406,329Change in
>         unrealized gain on financial derivative instruments
>         $
>         937
>         $
>         -Amortization of
>         loss on financial derivative instruments (note 15)
>         
>         (22,990)
>         
>         -Unrealized loss
>         on financial derivative instruments
>         $
>         (22,053)
>         $
>         -

8.

> The Trust's asset retirement obligation is based on the
>   Trust's net ownership in wells, facilities and the midstream assets and
>   represents management's estimate of the costs to abandon and reclaim those
>   wells, facilities and midstream assets as well as an estimate of the future
>   timing of the costs to be incurred.

The total undiscounted amount of future cash flows required
  to settle asset retirement obligations related to oil and gas operations is
  estimated to be $130.4 million. Payments to settle oil and gas asset
  retirement obligations occur over the operating lives of the assets estimated
  to be from two to 20 years.

The total undiscounted amount of future cash flows required
  to settle the midstream asset retirement obligations is estimated to be $26.1
  million. The estimated costs include such activities as dismantling,
  demolition and disposal of the facilities as well as remediation and
  restoration of the surface land.. Payments to settle the

- 13 -

---



> Midstream asset retirement obligations are expected to occur subsequent to
>   the closure of the facilities and related assets. Settlement of these
>   obligations is expected to occur in 30 to 35 years.

|                                                          |   | For the
        year ended
|--------------------------------------------------------- | - | --------------------------
|                                                          |   | December
        31,      
|                                                          |   | 2004                      
|Carrying amount, beginning of period                      | $ | 33,182                    
|Oil and gas producing corporate
        acquisitions      |   | 12,171                    
|Change in estimate                                        |   | (2,429)                   
|Increase in liabilites incurred during
        the period |   | 166                       
|Accretion expense                                         |   | 2,387                     
|Settlement of liabilities during the
        period       |   | (4,971)                   
|Carrying amount, end of period                            | $ | 40,506                    

9.

> The Trust has authorized capital of an unlimited number of common voting
>   trust units.
>   On 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 January 22, 2004 public offering. Proceeds from the issue
>   were initially used to pay down Provident's bank debt and throughout 2004 have
>   been used to finance the 2004 capital program.
>   On June 1, 2004 the Trust issued 13.4 million units (at an
>   ascribed value of $152.9) and a further 12.8 million units (at an ascribed
>   value of $145.7 million) as part of the consideration to acquire the
>   outstanding shares of Olympia Energy Inc. and Viracocha Energy Inc.
>   respectively. 1.325 million exchangeable shares of Provident Energy Ltd. were
>   issued pursuant to each transaction for a total of 2.65 million additional
>   exchangeable shares. The exchangeable shares will be automatically exchanged
>   for Trust Units on January 15, 2006, subject to extension at the option of the
>   Offeror. The exchange ratio for these shares is calculated with reference to
>   the distributions.
>   On July 6, 2004 the Trust issued 13.1 million units at
>   $10.40 per unit for proceeds of $136.2 million ($129.4 million net of issue
>   costs) pursuant to a June 17, 2004 public offering. Proceeds from the issue
>   applied to pay down the bridge financing used in the Breitburn Energy LLC
>   acquisition.
>   On October 4, 2004 the Trust issued 11.48 million units at
>   $10.95 per unit, for net proceeds (after underwriters' fees) of $119.4
>   million. Proceeds were used to fund the acquisition of the Orcutt property in
>   California ($58.5 million) and to repay bank debt.
>   In 2004 the Trust issued 4.2 million units related to
>   Provident's DRIP program, conversion of exchangeable shares to units,
>   conversion of convertible debentures to units and units issued pursuant to
>   Provident's Unit Option Plan. The net increase in unitholders' contributions
>   associated with these activities was $40.0 million.
>   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 13). The conversion ratio for the
>   exchangeable shares for the period January 17 to February 14, 2003 was equal
>   to one trust unit for one

-14-

---





> 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.
>   In 2003 the Trust issued 9.9 million units related to
>   Provident's DRIP program, conversion of exchangeable shares to units,
>   conversion of convertible debentures to units and units issued pursuant to
>   Provident's Unit Option Plan. The net increase in unitholders' contributions
>   associated with these activities was $98.9 million.







-15-

---





> Year ended December 31,2004
>       
>       
>       2003Trust Units
>       Number
>       
>       Amount
>       Number
>       
>       Amountof Units
>       
>       (000s)
>       of Units
>       
>       (000s)Balance at beginning
>       of period
>       82,824,688
>       $
>       803,299
>       53,729,335
>       $
>       513,835Issued to acquire
>       Olympia Energy Inc. (note 4)
>       13,385,579
>       
>       152,863
>       -
>       
>       -Issued to acquire
>       Viracocha Energy Ltd. (note 4)
>       12,758,386
>       
>       145,701
>       -
>       
>       -Issued for cash
>       29,080,000
>       
>       312,346
>       19,205,000
>       
>       201,653Exchangeable share
>       conversions
>       1,633,312
>       
>       15,343
>       5,726,525
>       
>       55,518Issued pursuant to
>       unit option plan
>       638,991
>       
>       4,677
>       202,446
>       
>       1,626Issued pursuant to
>       the distribution reinvestmentplan
>       1,745,418
>       
>       18,250
>       2,478,956
>       
>       25,880To be issued
>       pursuant to the distributionreinvestment plan
>       148,496
>       
>       1,616
>       141,361
>       
>       1,528Debenture
>       conversions
>       11,378
>       
>       124
>       1,341,065
>       
>       14,350Unit issue costs
>       -
>       
>       (15,826)
>       -
>       
>       (11,091)Balance at end of
>       period
>       142,226,248
>       $
>       1,438,393
>       82,824,688
>       $
>       803,299Year ended December 31,2004
>       
>       
>       2003Exchangeable
>       shares
>       Number
>       
>       Amount
>       Number
>       
>       AmountProvident
>       Acquisitions Inc.
>       of Units
>       
>       (000s)
>       of Units
>       
>       (000s)Balance at beginning
>       of period
>       534,357
>       $
>       5,829
>       5,227,844
>       $
>       57,036Converted to trust
>       units
>       (197,481)
>       
>       (2,154)
>       (4,693,487)
>       
>       (51,207)Balance, end of
>       period
>       336,876
>       
>       3,675
>       534,357
>       
>       5,829Exchange ratio, end
>       of period
>       1.42501
>       
>       
>       1.2517Trust units issuable
>       upon conversion, end of period
>       480,052
>       $
>       3,675
>       668,855
>       $
>       5,829Exchangeable
>       shares
>       Number
>       
>       Amount
>       Number
>       
>       AmountProvident Energy
>       Ltd.
>       of Units
>       
>       (000s)
>       of Units
>       
>       (000s)Balance at beginning
>       of period
>       1,279,227
>       $
>       13,689
>       -
>       $
>       -Issued to acquire
>       Provident Management Corp. (note 13)
>       -
>       
>       -
>       1,682,242
>       
>       18,000Converted to trust
>       units
>       (640,753)
>       
>       (6,856)
>       (403,015)
>       
>       (4,311)Balance, end of
>       period
>       638,474
>       
>       6,833
>       1,279,227
>       
>       13,689Exchange ratio, end
>       of period
>       1.35099
>       
>       -
>       1.18663Trust units issuable
>       upon conversion, end of period
>       862,572
>       $
>       6,833
>       1,517,969
>       $
>       13,689Exchangeable
>       shares (Series B)
>       Number
>       
>       Amount
>       Number
>       
>       AmountProvident Energy
>       Ltd.
>       of Units
>       
>       (000s)
>       of Units
>       
>       (000s)Balance at beginning
>       of period
>       -
>       $
>       -
>       -
>       $
>       -Issued to acquire
>       Olympia Energy Inc. (note 4)
>       1,325,000
>       
>       15,132
>       -
>       
>       -Issued to acquire
>       Viracocha Energy Inc. (note 4)
>       1,325,000
>       
>       15,132
>       -
>       
>       -Converted to trust
>       units
>       (554,729)
>       
>       (6,333)Balance, end of
>       period
>       2,095,271
>       
>       23,931
>       -
>       
>       -Exchange ratio, end
>       of period
>       1.06742
>       
>       -
>       -
>       
>       -Trust units issuable
>       upon conversion, end of period
>       2,236,534
>       $
>       23,931
>       -
>       $
>       -Total Trust unit
>       issuable upon conversionof all exchangeable
>       shares, end of period
>       3,579,158
>       $
>       34,439
>       2,186,824
>       $
>       19,518

-16-

---

The per trust unit amounts for 2004 were calculated based
  on the weighted average number of units outstanding of 116,627,982 which
  includes the shares exchangeable into trust units (2003 - 68,448,203). The
  diluted per trust unit amounts for 2004 are calculated including an additional
  179,428 trust units (2003 - 50,098) for the effect of the unit option plan.
  Provident's convertible debentures are not included in the computation of
  diluted earnings per unit as their effect is anti-dilutive.10.
Non-cash general & administrative

> (i)

> The Trust option plan (the "Plan") is administered by the
>     Board of Directors of Provident. Under the Plan, all directors, officers and
>     employees of Provident, are eligible to participate in the Plan. There are
>     8,000,000 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 six months
>     after grant and every year thereafter in equal increments except for options
>     granted to existing employees which vest immediately.

> Year endedDecember 31,2004
>         
>         2003Weighted
>         
>         WeightedNumber of
>         Average
>         Number of
>         AverageOptions
>         Exercise
>         Options
>         ExerciseOutstanding,
>         beginning of period
>         4,008,744
>         $11.06
>         796,810
>         $10.86Granted
>         1,909,067
>         10.89
>         3,443,550
>         11.09Exercised
>         (638,991)
>         10.96
>         (202,446)
>         10.62Cancelled
>         (78,489)
>         11.25
>         (29,170)
>         11.18Outstanding, end
>         of period
>         5,200,331
>         11.01
>         4,008,744
>         11.06Exercisable at end
>         of period
>         2,620,941
>         $11.05
>         1,535,004
>         $11.07At December 31, 2004, the Trust had 5,200,331 options
>     outstanding with strike prices ranging between $8.40 and $12.39 per unit.
>     The weighted average remaining contractual life of the options is 2.71 years
>     and the weighted average exercise price is $11.01 per unit excluding average
>     potential reductions to the strike prices of $1.08 per unit.
>     At December 31, 2003, the Trust had 4,008,744 options
>     outstanding with strike prices ranging from $8.40 and $12.39 per unit. The
>     weighted average remaining contractual life of the options was 3.09 years
>     and the weighted exercise price was $11.06 per unit excluding average
>     potential reductions to the strike prices of $1.26 per unit.
>     On December 31, 2004 the Trust prospectively applied the
>     fair value based method of accounting for the Plan. Previously, the Trust
>     applied the intrinsic value methodology due to the uncertainties of future
>     expected distributions. The Trust now uses the Black-Scholes option-pricing
>     model to calculate the estimated fair value of the outstanding options
>     issued on or after January 1, 2003 at their issue date. The Trust has
>     reevaluated the assumptions required to calculate the fair value of options
>     and considers the estimates required to calculate the fair value reasonably
>     estimated at the time of the issue of the options.

-17-

---





> In 2004 the Trust recorded unit-based compensation
>     expense (non-cash general and administrative) of $1.2 million, for the 5.4
>     million options granted on or after January 1, 2003 (2003 - $1.3 million)
>     net of the fourth quarter's compensation recovery of $0.3 million (2003 -
>     nil).
>     As at December 31, 2004, the following assumptions are
>     the weighted averages of the individual assumptions applied at each grant
>     date to arrive at an estimate of fair value of all granted options on or
>     after January 1, 2003 of $3.6 million:

> 2004 Granted Options
>         2003 Granted OptionsExpected annual dividend
>         8.00%
>         8.00%Expected
>         volatility
>         20.18%
>         19.46%Risk - free
>         interest rate
>         3.30%
>         3.66%Expected life of
>         option (yrs)
>         3.31
>         3.31Expected
>         forteitures
>         -
>         -Fair Value of Granted Options
>         $1.2 million
>         $2.4 millionIn the fourth quarter, 2004 the fair value calculation
>     resulted in a compensation recovery of $0.3M. This difference resulted from
>     the fair value expense of $0.9 million compared to the $1.2 million recorded
>     as compensation expense for the period ending September 30, 2004 under the
>     intrinsic value methodology. Fourth quarter compensation expense utilizing
>     the fair value based method was $0.3M. The remaining fair value of the
>     rights of $1.1 million, less any future cancellations, will be recognized in
>     earnings over the remaining vesting period the rights outstanding. The
>     following table reconciles the movement in the contributed surplus balance:
> (Cdn$ 000's)20042003Contributed surplus, beginning of the year$1,305$       -Compensation  expense, net of recovery1,1901,305Benefit on options exercised charged to unitholders' equity(493)-Balance, end of year$2,002$1,305
>   (ii)
>   Unit appreciation rightsDuring 2004, the Trust put in place a program whereby certain employees
>     of its U.S subsidiary are granted unit appreciation rights ("UAR's") which
>     entitle the employee to receive cash compensation in relation to the value
>     of a specified number of underlying notional trust units. UAR's vest evenly
>     over a period of three years commencing one year after grant and expire
>     after four years. The UAR's, upon vesting, provide certain employees
>     entitlement to receive a cash payment equal to the excess of the market
>     price of the Trust's Units over the exercise price of the right less
>     notionally accrued distributions in excess of an 8 percent return. These
>     prices are denominated in US dollars and are based on quoted US
>     distributions and market prices.
>     The following table summarizes the information about UAR's

> As at December 31, 2004Number of Units
>   Weighted AverageAppreciation Rights
>   Exercise PriceOutstanding, beginning of year
>   -
>   -Granted
>   976,000
>   $9.59Exercised
>   -
>   -Cancelled
>   -
>   -Outstanding, end of year
>   976,000
>   $9.59Exercisable, end of year
>   -
>   -Weighted average remaining contract life (years)
>   3.48Average potential reductions to exercise price
>   $0.35The fair value associated with the UAR's is expensed in the
> statement of income over the vesting period. During the year, the Trust recorded
> compensation costs of $0.8 million with respect to the outstanding UAR's (2003 -
> nil).

-18-

---

11.
Reconciliation of cash flow and distributions

> Year endedDecember 31,2004
>         
>         2003Cash provided by operating activities
>         $
>         187,823
>         $
>         102,835Change in non cash working capital
>         
>         (5,796)
>         
>         23,377Site restoration expenditures
>         
>         3,219
>         
>         2,153Cash flow from operations
>         
>         185,246
>         
>         128,365Cash (reserved) used for financing andinvesting activities
>         
>         (20,618)
>         
>         1,247Cash distributions to unitholders
>         
>         164,628
>         
>         129,612Accumulated cash distributions,beginning of period
>         
>         248,018
>         
>         118,406Accumulated cash distributions, paid and
>         declared,end of period
>         $
>         412,646
>         $
>         248,018Cash (reserved) used for financing and investing activities is a
>   discretionary amount and represents the difference between cash flow from
>   operations less distributions.

12.

> Under this method, future income tax assets and liabilities are recognized
>   based on the estimated tax effects of temporary differences in the carrying
>   value of assets and liabilities, reported in the financial statements of the
>   corporate subsidiaries, and their respective tax bases, using income tax rates
>   substantively enacted on the consolidated balance sheet date:

|                                                                              |   | December 31, |  
|----------------------------------------------------------------------------- | - | ------------ | -
|                                                                              |   | 2004         |  
|Petroleum and
        natural gas properties, production facilities and other | $ | 70,301       | $
|Midstream
        facilities                                                  |   | 328          |  
|                                                                              | $ | 70,629       | $

-19-

---

The income tax provision differs from the expected amount calculated by
  applying the Canadian combined federal and provincial income tax rate of 38.87
  percent (2003 - 40.6 percent) as follows:

|                                                        |   | Year ended
|------------------------------------------------------- | - | ----------
|                                                        |   | 2004      
|Expected income
        tax recovery                    | $ | (4,186)   
|Increase
        (decrease) resulting from:             |   |           
|Non-deductible
        Crown charges and other payments |   | 17,087    
|Federal resource
        allowance                      |   | (7,535)   
|Alberta Royalty
        Tax Credit                      |   | (194)     
|Income of the
        Trust and other                   |   | (41,336)  
|Capital Taxes                                           |   | 5,921     
|Witholding tax and
        other                        |   | 1,282     
|Income tax rate
        changes                         |   | (4,413)   
|                                                        | $ | (33,374)  

13.

> On December 30, 2004, at the conclusion of a competitive
>   process, Provident sold properties to a private company on whose board two of
>   the directors of Provident sit and in which they own shares. The properties
>   were sold for consideration of $3.5 million of which $0.5 million was cash and
>   $3.0 million consisted of 10,000,000 common shares valued at $0.30 per share.
>   The carrying value of these shares are included in investments on the balance
>   sheet. The transaction was recorded at fair value.
>   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 two 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, 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.

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.

14.

> Certain comparative numbers have been restated to conform to the current
>   year presentation.

15.

Financial instruments of the Trust carried on the
  consolidated balance sheet consist mainly of cash and cash equivalents,
  accounts receivable, reclamation fund investments, current liabilities, other
  long-term liabilities, asset retirement obligations, commodity and foreign
  currency contracts and long-term debt. Except as noted

-20-

---





> below, as at December 31, 2004 and 2003, there were no significant
>   differences between the carrying value of these financial instruments and
>   their estimated fair value.
>   Substantially all of the Trust's accounts receivable are
>   due from customers in the oil and gas industry and are subject to the normal
>   industry credit risks. The Trust partially mitigates associated credit risk by
>   limiting transactions with certain counterparties to limits imposed by the
>   Trust based on the Trust's assessment of the creditworthiness of such
>   counterparties. The carrying value of accounts receivable reflects
>   management's assessment of the associated credit risks. With respect to
>   counterparties to financial instruments, the Trust partially mitigates
>   associated credit risk by limiting transactions to counterparties with
>   investment grade credit ratings.
>   At January 1, 2004 the Trust adopted CICA accounting
>   guideline 13 "Hedging relationships" resulting in the recognition of an
>   unrealized loss of $25.1 million in deferred charges on the consolidated
>   balance sheet that is being amortized to income in the same period as the
>   corresponding losses associated with the hedged items.

|Deferred
        derivative loss                          |   |         
|--------------------------------------------------------- | - | --------
|Non-hedging
        derivative liability, January 1, 2004 | $ | 25,134  
|Derivative
        instruments amortized                  |   | (22,990)
|Deferred
        derivative loss, December 31, 2004       | $ | 2,144   

Provident'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.

With respect to financial instruments, Provident could be
  exposed to losses if a counter party fails to perform in accordance with the
  terms of the contract. This risk is managed by diversifying the derivative
  portfolio among counter parties meeting certain financial criteria.

(i)

> a)

> For 2004, Provident paid out $56.2 million to settle
>       various oil market based contracts on an aggregate volume of 2,729,700
>       barrels. For 2003, Provident paid out $23.9 million to settle various oil
>       market based contracts on an aggregate volume of 1,867,500 barrels. The
>       estimated value of contracts in place if settled at market prices at
>       December 31, 2004 would have resulted in an opportunity cost of $25.2
>       million (December 31, 2003 -$21.1 million). The contracts in place at
>       December 31, 2004 are summarized in the following table:

|COGP |           |        |       |                                           
|---- | --------- | ------ | ----- | ------------------------------------------
|Year | Product   | Volume | Terms | Effective Period                          
|2005 | Light Oil | 2,750  | Bpd   | WTI US $26.07 per bbl (1)                 
|     |           | 500    | Bpd   | Costless collar US $26.00 - $30.10 per bbl
|     |           |        |       |                                           

|                  
|------------------
|USOGP (BreitbBurn)
|Year              
|2005              
|                  
|                  
|                  
|                  



-21-

---



> (1)
>         Represents a
>         number of transactions entered into over an extended period of time.(2)
>         Natural gas
>         contracts are settled against AECO monthly index.(3)
>         Provides a
>         floor price while allowing percentage participation above strike price.
>   b)Natural GasFor 2004, Provident paid $10.4 million to settle various
>     natural gas market based contracts on an aggregate of 10,946,000 gigajoules
>     ("GJ"). For 2003, Provident received $25.0 million to settle various natural
>     gas market based contracts on an aggregate of 23,063,900 gigajoules ("GJ").
>     As at December 31, 2004 the estimated value of contracts in place settled at
>     market prices at December 31 would have resulted in an opportunity gain of
>     $0.3 million (December 31, 2003 - an opportunity cost of $4.1 million). The
>     contracts in place at December 31, 2004 are summarized in the following
>     table:
>     Year
>         Product
>         Volume
>         Terms
>         Effective Period2005
>         Natural Gas (2)
>         3,000
>         Gjpd
>         Cdn $5.90 per gj
>         January 1 - March 313,000
>         Gjpd
>         Costless collar Cdn $5.25 -
>         $7.10 per gj
>         January 1 - March 312,000
>         Gjpd
>         Costless collar Cdn $5.50 -
>         $7.29 per gj
>         January 1 - March 312,000
>         Gjpd
>         Costless collar Cdn $5.50 -
>         $7.40 per gj
>         January 1 - March 311,000
>         Gjpd
>         Costless collar Cdn $5.50 -
>         $7.60 per gj
>         January 1 - March 312,000
>         Gjpd
>         Costless collar Cdn $5.50 -
>         $7.38 per gj
>         January 1 - March 31600
>         Gjpd
>         Cdn $5.39 per gj
>         January 1 - October 312,000
>         Gjpd
>         Costless collar Cdn $5.50 -
>         $6.88 per gj
>         January 1 - October 315,000
>         Gjpd
>         Costless collar Cdn $6.00 -
>         $9.10 per gj
>         January 1 - January 315,000
>         Gjpd
>         Puts Cdn $6.50 per gj (1)
>         April 1 - October 315,000
>         Gjpd
>         Participating Swaps Cdn $6.00
>         per gj (3)
>         April 1 - October 31c)
>   OtherProvident paid $4.8 million to settle various midstream and marketing
>     contracts which were entered into to fix prices on product sales.
>     Year
>         Product
>         Volume
>         Terms
>         Effective Period2005
>         Propane
>         52,000
>         Bbls
>         US $0.88077 per usg (US$36.99
>         per bbl) (1)
>         January 1 - January 31Foreign
>         
>         
>         Sell US $6,500,000 @ $1.24128
>         (1)
>         January 1 - March 24ExchangeAvg Rate Forward US
>         $4,200,000 + 3 pts
>         January 25, 2005 -January 25, 2006Power
>         2.5
>         MW/h
>         $45.875 MW/h
>         January 1 - December 31
>   d)
>   Foreign exchange contractsProvident had foreign exchange sell contracts in place in 2004 for a
>     total gain of $2.3 million . As at December 31, 2004 the estimated value of
>     contracts in place settles at foreign exchange rates at December 31 would
>     have resulted in an opportunity gain of $0.2 million. The foreign exchange
>     gains have been included in note 18, as component of realized gain or loss
>     on non-hedging derivative instruments and allocated to their respective
>     business segments.

-22-

---





16.        Cash reserve for future site
reclamation

> Provident 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, 2004, $2.8 million was contributed to the reserve and
>   actual expenditures totaled $3.2 million. For the year ended December 31,
>   2003, $2.5 million was added to the cash reserve and actual expenditures
>   totaled $2.2 million.

17.       Commitments

> Provident has office lease commitments that extend through
>   April 2013. Future minimum lease payments for the following five years are:
>   2005 - $2.4 million; 2006 - $2.7 million; 2007 - $2.8 million, 2008 - $2.9
>   million; 2009 - $3.1 million, and $2.5 million thereafter.

18.        Segmented information

> The Trust's business activities are conducted through three business
>   segments: Canadian oil and natural gas production, United States oil and
>   natural gas production and midstream services and marketing.
>   Oil and natural gas production in Canada and the United
>   States 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.
>   Geographically the Trust operates in Canada and the USA in
>   the oil and gas production business segment. The geographic components have
>   been presented as well as the midstream and marketing business that operates
>   in Canada. Interest and long-term debt have been allocated to the business
>   segments on the basis of invested capital at book value.



-23-

---





|                                                         |             |               |             |               |                              |                    |   |           |   |           |   |          
|-------------------------------------------------------- | ----------- | ------------- | ----------- | ------------- | ---------------------------- | ------------------ | - | --------- | - | --------- | - | ---------
|                                                         |             |               |             |               | Year ended December 31, 2004 |                    |   |           |  
|                                                         |             |               |             |               |                              |                    |   |           |   |           |   |          
|                                                         | Canada Oil  | United States |             |               |                              |                    |   |           |   |          
|                                                         | and Natural |               | Oil and     | Total Oil and |                              | Midstream          |   |           |   |          
|                                                         |             | Gas           | Natural Gas | Natural Gas   | Services and                 | Inter-
    segment |   |          
|                                                         | Production  | Production    | Production  |               | Marketing                    | Elimination        |   | Total    
|Revenue                                                  |             |               |             |               |                              |                    |   |           |   |           |   |          
|Gross production revenue                                 | $           | 405,181       | $           | 44,688        | $                            | 449,869            | $ | -         | $ | -         | $ | 449,869  
|Royalties                                                |             | (85,190)      |             | (4,009)       |                              | (89,199)           |   | -         |   | -         |   | (89,199) 
|Product sales and service revenue                        |             |               |             |               |                              |                    |   |           |   |           |   |          
|                                                         |             | -             |             | -             |                              | -                  |   | 1,031,019 |   | (190,835) |   | 840,184  
|Realized gain/(loss) on financial derivative             |             | (65,366)      |             | (425)         |                              | (65,791)           |   | (3,153)   |   | -         |   | (68,944) 
|instruments                                              |             |               |             |               |                              |                    |   |           |   |           |   |          
|                                                         |             | 254,625       |             | 40,254        |                              | 294,879            |   | 1,027,866 |   | (190,835) |   | 1,131,910
|Expenses                                                 |             |               |             |               |                              |                    |   |           |   |           |   |          
|Cost of goods sold                                       |             | -             |             | -             |                              | -                  |   | 932,476   |   | (190,835) |   | 741,641  
|Operating expenses                                       |             |               |             |               |                              |                    |   |           |   |           |   |          
|                                                         |             | 90,330        |             | 13,173        |                              | 103,503            |   | 37,990    |   | -         |   | 141,493  
|Transportation                                           |             |               |             |               |                              |                    |   |           |   |           |   |          
|                                                         |             | 5,087         |             | -             |                              | 5,087              |   | -         |   | -         |   | 5,087    
|Foreign exchange (gain) loss                             |             | (4)           |             | (2,239)       |                              | (2,243)            |   | 763       |   | -         |   | (1,480)  
|General and administrative                               |             | 16,439        |             | 4,113         |                              | 20,552             |   | 6,552     |   | -         |   | 27,104   
|                                                         |             | 111,852       |             | 15,047        |                              | 126,899            |   | 977,781   |   | (190,835) |   | 913,845  
|Earnings (loss) before interest, taxes,
    depletion,   |             |               |             |               |                              |                    |   |           |   |           |   |          
|depreciation, accretion and non-cash revenue             |             | 142,773       |             | 25,207        |                              | 167,980            |   | 50,085    |   | -         |   | 218,065  
|Non-cash revenue                                         |             |               |             |               |                              |                    |   |           |   |           |   |          
|Unrealized gain/(loss) on non-hedging
    derivative     |             |               |             |               |                              |                    |   |           |   |           |   |          
|instruments                                              |             | 3,788         |             | (3,182)       |                              | 606                |   | 331       |   | -         |   | 937      
|Amortization of gain/(loss) on non-hedging               |             |               |             |               |                              |                    |   |           |   |           |   |          
|derivative instruments                                   |             | (22,990)      |             | -             |                              | (22,990)           |   | -         |   | -         |   | (22,990) 
|                                                         |             | (19,202)      | -           | (3,182)       | -                            | (22,384)           | - | 331       | - | -         |   | (22,053) 
|Other expenses                                           |             |               |             |               |                              |                    |   |           |   |           |   |          
|Depletion, depreciation and accretion                    |             | 160,271       |             | 7,402         |                              | 167,673            |   | 9,609     |   | -         |   | 177,282  
|Interest on long-term debt & convertible
    debentures  |             |               |             |               |                              |                    |   |           |   |           |   |          
|                                                         |             | 16,338        |             | 2,547         |                              | 18,885             |   | 6,731     |   | -         |   | 25,616   
|Accretion and amortization on
    convertible debentures |             |               |             |               |                              |                    |   |           |   |           |  
|                                                         |             | 1,801         |             | 175           |                              | 1,976              |   | 832       |   |           |   | 2,808    
|Unrealized foreign exchange (gain) loss                  |             |               |             | (744)         |                              | (744)              |   |           |   | -         |   | (744)    
|Non-cash general and administrative                      |             |               |             |               |                              |                    |   |           |   |           |   |          
|                                                         |             | 877           |             | 822           |                              | 1,699              |   | 120       |   | -         |   | 1,819    
|Capital taxes                                            |             |               |             |               |                              |                    |   |           |   |           |   |          
|                                                         |             | 5,292         |             | -             |                              | 5,292              |   | 629       |   | -         |   | 5,921    
|Current and withholding taxes                            |             | -             |             | 1,201         |                              | 1,201              |   | 81        |   | -         |   | 1,282    
|Future income tax expense (recovery)                     |             |               |             |               |                              |                    |   |           |   |           |   |          
|                                                         |             | (40,457)      |             | -             |                              | (40,457)           |   | (120)     |   | -         |   | (40,577) 
|                                                         |             | 144,122       |             | 11,403        |                              | 155,525            |   | 17,882    |   | -         |   | 173,407  
|Non-controlling interest                                 |             | -             |             | 923           |                              | 923                |   |           |   |           |   | 923      
|                                                         |             |               |             |               |                              |                    |   |           |   |           |   |          
|Net income (loss ) for the year                          | $           | (20,551)      |             | 9,699         | $                            | (10,852)           |   | 32,534    | $ | -         | $ | 21,682   



-24-

---





|                                                         |             |               |             |               |                              |               |   |           |   |           |   |          
|-------------------------------------------------------- | ----------- | ------------- | ----------- | ------------- | ---------------------------- | ------------- | - | --------- | - | --------- | - | ---------
|                                                         |             |               |             |               | Year ended December 31, 2004 |               |   |           |  
|                                                         |             |               |             |               |                              |               |   |           |   |           |   |          
|                                                         | Canada Oil  | United States |             |               |                              |               |   |           |   |          
|                                                         | and Natural |               | Oil
    and | Total Oil and |                              | Midstream     |   |           |   |          
|                                                         |             | Gas           | Natural Gas | Natural Gas   | Services and                 | Inter-segment |   |          
|                                                         | Production  | Production    | Production  |               | Marketing                    | Elimination   |   | Total    
|Revenue                                                  |             |               |             |               |                              |               |   |           |   |           |   |          
|Gross production
    revenue                             | $           | 405,181       | $           | 44,688        | $                            | 449,869       | $ | -         | $ | -         | $ | 449,869  
|Royalties                                                |             | (85,190)      |             | (4,009)       |                              | (89,199)      |   | -         |   | -         |   | (89,199) 
|Product sales and
    service revenue                    |             |               |             |               |                              |               |   |           |   |           |   |          
|                                                         |             | -             |             | -             |                              | -             |   | 1,031,019 |   | (190,835) |   | 840,184  
|Realized gain/(loss)
    on financial derivative         |             | (65,366)      |             | (425)         |                              | (65,791)      |   | (3,153)   |   | -         |   | (68,944) 
|instruments                                              |             |               |             |               |                              |               |   |           |   |           |   |          
|                                                         |             | 254,625       |             | 40,254        |                              | 294,879       |   | 1,027,866 |   | (190,835) |   | 1,131,910
|Expenses                                                 |             |               |             |               |                              |               |   |           |   |           |   |          
|Cost of goods sold                                       |             | -             |             | -             |                              | -             |   | 932,476   |   | (190,835) |   | 741,641  
|Operating expenses                                       |             |               |             |               |                              |               |   |           |   |           |   |          
|                                                         |             | 90,330        |             | 13,173        |                              | 103,503       |   | 37,990    |   | -         |   | 141,493  
|Transportation                                           |             |               |             |               |                              |               |   |           |   |           |   |          
|                                                         |             | 5,087         |             | -             |                              | 5,087         |   | -         |   | -         |   | 5,087    
|Foreign exchange
    (gain) loss                         |             | (4)           |             | (2,239)       |                              | (2,243)       |   | 763       |   | -         |   | (1,480)  
|General and
    administrative                           |             | 16,439        |             | 4,113         |                              | 20,552        |   | 6,552     |   | -         |   | 27,104   
|                                                         |             | 111,852       |             | 15,047        |                              | 126,899       |   | 977,781   |   | (190,835) |   | 913,845  
|Earnings (loss) before
    interest, taxes, depletion,   |             |               |             |               |                              |               |   |           |   |           |   |          
|depreciation,
    accretion and non-cash revenue         |             | 142,773       |             | 25,207        |                              | 167,980       |   | 50,085    |   | -         |   | 218,065  
|Non-cash revenue                                         |             |               |             |               |                              |               |   |           |   |           |   |          
|Unrealized gain/(loss)
    on non-hedging derivative     |             |               |             |               |                              |               |   |           |   |           |   |          
|instruments                                              |             | 3,788         |             | (3,182)       |                              | 606           |   | 331       |   | -         |   | 937      
|Amortization of
    gain/(loss) on non-hedging           |             |               |             |               |                              |               |   |           |   |           |   |          
|derivative instruments                                   |             | (22,990)      |             | -             |                              | (22,990)      |   | -         |   | -         |   | (22,990) 
|                                                         |             | (19,202)      | -           | (3,182)       | -                            | (22,384)      | - | 331       | - | -         |   | (22,053) 
|Other expenses                                           |             |               |             |               |                              |               |   |           |   |           |   |          
|Depletion,
    depreciation and accretion                |             | 160,271       |             | 7,402         |                              | 167,673       |   | 9,609     |   | -         |   | 177,282  
|Interest on long-term
    debt & convertible debentures  |             |               |             |               |                              |               |   |           |   |           |   |          
|                                                         |             | 16,338        |             | 2,547         |                              | 18,885        |   | 6,731     |   | -         |   | 25,616   
|Accretion
    and amortization on convertible debentures |             |               |             |               |                              |               |   |           |   |           |  
|                                                         |             | 1,801         |             | 175           |                              | 1,976         |   | 832       |   |           |   | 2,808    
|Unrealized foreign
    exchange (gain) loss              |             |               |             | (744)         |                              | (744)         |   |           |   | -         |   | (744)    
|Non-cash general and
    administrative                  |             |               |             |               |                              |               |   |           |   |           |   |          
|                                                         |             | 877           |             | 822           |                              | 1,699         |   | 120       |   | -         |   | 1,819    
|Capital taxes                                            |             |               |             |               |                              |               |   |           |   |           |   |          
|                                                         |             | 5,292         |             | -             |                              | 5,292         |   | 629       |   | -         |   | 5,921    
|Current and
    withholding taxes                        |             | -             |             | 1,201         |                              | 1,201         |   | 81        |   | -         |   | 1,282    
|Future income tax
    expense (recovery)                 |             |               |             |               |                              |               |   |           |   |           |   |          
|                                                         |             | (40,457)      |             | -             |                              | (40,457)      |   | (120)     |   | -         |   | (40,577) 
|                                                         |             | 144,122       |             | 11,403        |                              | 155,525       |   | 17,882    |   | -         |   | 173,407  
|Non-controlling
    interest                             |             | -             |             | 923           |                              | 923           |   |           |   |           |   | 923      
|                                                         |             |               |             |               |                              |               |   |           |   |           |   |          
|Net income (loss )
    for the year                      | $           | (20,551)      |             | 9,699         | $                            | (10,852)      |   | 32,534    | $ | -         | $ | 21,682   



-24-

---



|                                                | Year ended December 31, 2004
|----------------------------------------------- | ----------------------------
|                                                |                             
|                                                | Canada Oil                  
|                                                | and Natural                 
|                                                |                             
|                                                | Production                  
|Selected balance sheet
    items                |                             
|                                                |                             
|                                                |                             
|Capital Assets                                  |                             
|Property, plant and equipment net               | $                           
|Goodwill                                        | $                           
|                                                |                             
|                                                |                             
|Capital Expenditures                            |                             
|Property, plant and equipment net               | $                           
|Property, plant and equipment through corporate |                             
|acquisitions                                    |                             
|                                                | $                           
|Goodwill additions                              | $                           
|Working capital                                 |                             
|Accounts receivable                             | $                           
|Petroleum product inventory                     |                             
|Accounts payable and accrued liabilities        | $                           
|Long-term debt                                  | $                           



-25-

---



|Year ended December
    31, 2003(1)            |   |            |   |           |   |             |   |         
|---------------------------------------------- | - | ---------- | - | --------- | - | ----------- | - | --------
|                                               |   | Oil and    |   | Midstream |   |             |   |         
|                                               |   | Natural    |   | Services  |   | Inter-      |   |         
|                                               |   | Gas        |   | and       |   | segment     |   |         
|                                               |   | Production |   | Marketing |   | Elimination |   | Total   
|Revenue                                        |   |            |   |           |   |             |   |         
|Gross production revenue                       | $ | 305,531    | $ | -         |   | -           | $ | 305,531 
|Royalties                                      |   | (72,869)   |   | -         |   | -           |   | (72,869)
|Product sales and service revenue              |   | -          |   | 197,148   |   | (24,957)    |   | 172,191 
|Other revenue                                  |   | 1,476      |   | -         |   | -           |   | 1,476   
|                                               |   | 234,138    |   | 197,148   |   | (24,957)    |   | 406,329 
|                                               |   |            |   |           |   |             |   |         
|Expenses                                       |   |            |   |           |   |             |   |         
|Cost of goods sold                             |   | -          |   | 178,104   |   | (24,957)    |   | 153,147 
|Production, operating, and maintenance         |   | 76,396     |   | 7,644     |   | -           |   | 84,040  
|Transportation                                 |   | 5,447      |   | -         |   | -           |   | 5,447   
|Cash general and administrative                |   | 14,289     |   | 1,076     |   | -           |   | 15,365  
|Non-cash general and administrative            |   | 1,223      |   | 82        |   | -           |   | 1,305   
|Foreign exchange                               |   | 180        |   |           |   |             |   | 180     
|Management internalization                     |   | 18,592     |   | -         |   | -           |   | 18,592  
|                                               |   | 116,127    |   | 186,906   |   | (24,957)    |   | 278,076 
|                                               |   |            |   |           |   |             |   |         
|Earnings before
    interest taxes, depletion, |   |            |   |           |   |             |   |         
|depreciation and
    accretion                 |   | 118,011    |   | 10,242    |   | -           |   | 128,253 
|                                               |   |            |   |           |   |             |   |         
|Interest on long-term
    debt and convertible |   |            |   |           |   |             |   |         
|debentures                                     |   | 15,709     |   | 1,365     |   | -           |   | 17,074  
|Accretion and
    amortization on convertible  |   |            |   |           |   |             |   |         
|debentures                                     |   | 2,405      |   | 209       |   |             |   | 2,614   
|Depletion,
    depreciation and accretion      |   | 136,066    |   | 2,206     |   | -           |   | 138,272 
|Capital taxes                                  |   | 3,177      |   | 155       |   | -           |   | 3,332   
|Future income tax
    recovery (Note 15)       |   | (55,074)   |   | (1,404)   |   | -           |   | (56,478)
|                                               |   | 102,283    |   | 2,531     |   | -           |   | 104,814 
|                                               |   |            |   |           |   |             |   |         
|Net income (loss)
    for the period           | $ | 15,728     | $ | 7,711     |   | -           | $ | 23,439  
|                                               |   |            |   |           |   |             |   |         
|                                               |   |            |   |           |   |             |   |         
|Capital
    Expenditures                       |   |            |   |           |   |             |   |         
|Acquisition of Redwater                        | $ | -          | $ | 298,638   | $ | -           | $ | 298,638 
|Property, plant and equipment                  | $ | 31,628     | $ | -         | $ | -           | $ | 31,628  
|Selected balance
    sheet items               |   |            |   |           |   |             |   |         
|Working capital                                |   |            |   |           |   |             |   |         
|Accounts receivable                            | $ | 47,691     | $ | 76,106    | $ | (4,907)     | $ | 118,890 
|Petroleum product inventory                    | $ | -          | $ | 24,206    | $ | -           | $ | 24,206  
|Accounts payable                               | $ | 52,146     | $ | 74,593    | $ | (4,907)     | $ | 121,832 
|Long-term debt                                 | $ | 243,334    | $ | 113,239   | $ | -           | $ | 356,573 



(1)Restated - note 3

---





19.Subsequent event

> On February 9, 2005 the Trust announced it's intention to
>   issue 8.4 million Trust units at $12.00 per unit for proceeds of $100.8
>   million ($95.8 million net of issue costs) and $100 million (($96.0 million
>   net of issue costs) of 6.5 percent convertible debentures pursuant to a final
>   prospectus dated February 18, 2005. The bought deal financing closed March 1,
>   2005. On March 2, 2005, the proceeds were used to pay for the CAD$96 million
>   (USD$75 million) Nautilus corporate acquisition by Provident Energy's U.S.
>   subsidiary Breitburn Energy L.P. The remainder of the funds were used to pay
>   down Provident Energy's long-term debt.

20.

The 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.

> Consolidated Statement of Earnings - U.S. GAAP

|For the year ending December 31                                                | 2004 |          | 2003
(restated -
note 3)
|------------------------------------------------------------------------------ | ---- | -------- | ------------------------
|(Cdn$000s, except per unit numbers)                                            |      |          |                         
|Net income as reported                                                         | $    | 21,682   |                         
|Adjustments                                                                    |      |          |                         
|Depletion, depreciation and accretion (a) (b)                                  |      | 5,067    |                         
|Depletion, depreciation and accretion other (a)                                |      | (58,065) |                         
|FAS 133 adjustment (c)                                                         |      | 22,990   |                         
|Non-cash general and administrative (g)                                        |      | 415      |                         
|Future income recovery (taxes) (a) (b) (c) (e)                                 |      | 9,556    |                         
|Accretion on convertible debentures (j)                                        |      | 2,973    |                         
|Income before cumulative effect of a change in accounting policy
  - U.S. GAAP | $    | 4,618    |                         
|Net income, before change in accounting policy, per unit
  - basic and diluted |      | 0.04     |                         
|Effect of a change in accounting policy due to ARO (b)                         |      |          |                         
|Depletion, depreciation, and accretion                                         |      | -        |                         
|Future income tax recovery                                                     |      | -        |                         
|Net income
  - U.S. GAAP                                                       |      | 4,618    |                         
|Net income per unit
  - basic and diluted                                      | $    | 0.04     |                         



-27-

---



Condensed Consolidated Balance Sheet

|As at December 31                           |   |           |   |           |   |             |   |            
|------------------------------------------- | - | --------- | - | --------- | - | ----------- | - | -----------
|(Canadian
    dollars, 000's)               |   | 2004      |   | 2003     
|                                            |   | Canadian  |   | U.S.      |   | Canadian    |   | U.S.       
|                                            |   | GAAP      |   | GAAP      |   | GAAP        |   | GAAP       
|                                            |   |           |   |           |   | (restated - |   | (restated -
|                                            |   |           |   |           |   | note 3)     |   | note 3)    
|Assets                                      |   |           |   |           |   |             |   |            
|Deferred
    derivative loss (c)            | $ | 2,144     | $ | -         | $ | -           | $ | -          
|Accounts
    receivable (h)                 |   | 143,142   |   | 145,442   |   | -           |   | -          
|Property, plant
    and equipment (a) (b)   |   | 1,299,654 |   | 1,229,468 |   | 884,891     |   | 867,703    
|Liabilities and
    unitholders' equity     |   |           |   |           |   |             |   |            
|Other liability
    (c)                     |   | 24,524    |   | 24,524    |   | -           |   | 25,134     
|Long-term debt
    (j)                      |   | 432,206   |   | 452,150   |   | 356,573     |   | 375,900    
|Future income
    taxes (a) (b) (c) (e) (h) |   | 70,629    |   | 47,286    |   | 58,805      |   | 44,124     
|Convertible
    debentures equity           |   |           |   |           |   |             |   |            
|component (j)                               |   | 9,785     |   | -         |   | 7,908       |   | -          
|Unitholders'
    contributions (d)          |   | 1,438,393 |   | 1,442,376 |   | 803,299     |   | 807,282    
|Contributed
    surplus (g)                 |   | 2,002     |   | 3,020     |   | 1,305       |   | 2,738      
|Cumulative
    translation adjustment (i)   |   | (28,848)  |   | -         |   | -           |   | -          
|Accumulated
    income (loss)               |   | 1,844     |   | (43,380)  |   | (19,838)    |   | (47,998)   
|Accumulated other
    comprehensive         |   |           |   |           |   |             |   |            
|loss (h) (i)                                | $ | -         | $ | (27,442)  | $ | -           | $ | -          
|                                            |   |           |   |           |   |             |   |            

> (a)

In computing its consolidated net earnings for U.S. GAAP purposes, the
  Trust recorded additional depletion in 2004 as a result of the application of
  the ceiling test. These charges were not required under the Canadian GAAP
  ceiling tests. As a result of the U.S. GAAP ceiling test, there was a $58.1
  million charge for ceiling test impairment and a future tax recovery of $19.8
  million.

(b)

(c)



-28-

---

hedged items. For the period ending December 31, 2004, $23.0 million of
  this deferred charge has been amortized. Under U.S. GAAP the amortization of
  the deferred charge has already been captured in prior period accumulated
  losses. At the completion of the amortization period of the deferred charge,
  there will be no further U.S./Canadian GAAP differences related to the
  adoption of this standard.
  (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 and operations and accumulated income (loss) are prepared in accordance
  with Canadian GAAP and conform in all material respects with U.S. GAAP except
  for the following; (i) Canadian GAAP allows for the presentation of 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. (ii)
  U.S. GAAP requires disclosure on the consolidated statement of operations when
  depreciation, depletion and amortization are excluded from cost of goods sold.
  This disclosure has not been noted on the face of the consolidated statement
  of operations.

(g)
  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 options granted during or subsequent to 2003
  are fair valued. Under FAS 123, all option grants are fair valued.

(h)
  Included in accounts receivable is
  a marketable security that is being held for sale. The Trust follows the cost
  method of accounting for an investment in a marketable security as established
  by the CICA. Under this accounting policy, the investment is initially
  recorded at cost with dividends recorded as income. Under U.S. GAAP, the
  marketable securities are considered held for sale and recorded on the balance
  sheet at fair value. The corresponding difference between the cost method and
  fair value is recorded to other comprehensive loss in the current year and
  results in a Canadian/U.S. GAAP difference.

(i)
  U.S. GAAP requires gains or losses
  arising from the translation of self-sustaining operations to be included in
  other comprehensive losses. Canadian GAAP requires these amounts to be
  recorded in unitholders' contributions.

(j)
  Effective December 31, 2004, the
  Trust retroactively adopted the revised CICA Handbook Section 3860 ("HB
  3860"), "Financial Instruments - Presentation and Disclosure" for financial
  instruments that may be settled at the issuer's option in cash or its own
  equity. As a result of the implementation of this standard, a U.S./Canadian
  GAAP difference has arisen. Under U.S. GAAP, the convertible debentures are
  disclosed as long-term debt at their face value versus Canadian GAAP that
  requires discounting of the convertible debentures, accretion expense to
  represent the unwinding of the discounted convertible debentures and a value
  be assigned within equity to the conversion feature attached to the
  convertible debentures.

Recent US and Canadian Accounting Pronouncements

Variable interest entities

In 2003, FASB issued Interpretation Number 46R, "Consolidation of Variable
Interest Entities, and 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
released accounting guideline 15, "Consolidation of Variable Interest Entities"
effective for financial years starting on or after November 1, 2004. At December
31, 2004 Provident did not have any variable interests in special purpose
entities.

-29-

---







Share-based payment

In 2004, FASB issued revised FAS 123 "Share-Based Payment". This amended
statement eliminates the alternative to use Accounting Principles Board ("APB")
Opinion No. 25's intrinsic value method of accounting, as was provided in the
originally issued Statement 123. As a result, public entities are required to
use the grant-date fair value of the award in measuring the cost of employee
services received in exchange for an equity award of equity instruments.
Compensation cost is not recognized for equity instruments for which employees
do not render the requisite service. This amended statement is effective the
beginning of the first interim or annual reporting period that begins after June
15, 2005. The Trust is currently assessing the impact of this statement on the
financial statements.

Exchange of non-monetary assets

In 2004, FASB issued FAS 153 "Exchange of Non-monetary Assets". This
statement is an amendment of APB Opinion No. 29 "Accounting for Non-monetary
Transactions". Based on the guidance in APB Opinion No. 29, exchanges on non-monetray
assets are to be measured based on the fair value of the assets exchanged.
Furthermore, APB Opinion No. 29 previously allowed for certain exceptions to
this fair value principle. FAS 153 eliminates APB Opinion No. 29's exception to
fair value for non-monetary exchanges of similar productive assets and replaces
this with a general exception for exchange of non-monetary assets that do not
have commercial substance. For purposes of this statement, a non-monetary
exchange is defined as having commercial substance when the future cash flows of
an entity are expected to change significantly as a result of the exchange. The
provisions of this statement are effective for non-monetary asset exchanges that
occur in fiscal periods beginning after June 15, 2005 and are to be applied
prospectively. Earlier application is permitted for non-monetary asset exchanges
that occur in fiscal periods beginning after the issue date of this statement.
The Trust is currently assessing the impact of this statement on the financial
statements.

Exchangeable shares

The CICA issued EIC 151, "Exchangeable Securities Issued by Subsidiaries of
Income Trusts" effective for financial periods ending on or after December 31,
2004. EIC 151 states that exchangeable securities issued by a subsidiary of an
Income Trust should be reflected as either non-controlling interest or debt on
the consolidated balance sheet unless they meet certain criteria. The Trust
assessed its exchangeable shares and determined that the criteria are satisfied
for reflection as equity on the consolidated balance sheet.

Subsequent to the Trust's assessment of its exchangeable shares , EIC-151 was
amended and will be effective for periods ending on or after June 30, 2005. The
amended EIC-151 criteria has removed the clause that exchangeable shares can be
reflected as equity if they are required to be redeemed into Trust units by a
fixed redemption date. As a result of this amendment, the Trust is reassessing
the criteria for reflection of its exchangeable shares as debt, non-controlling
interest or equity.

-30-

---

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, 2004, 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 (i)
  recorded, processed, summarized and reported within the time periods specified
  in Securities and Exchange Commission rules and forms and (ii) accumulated and
  communicated to the registrant's management, including its principal executive
  officer and principal financial officer, to allow timely decisions regarding
  required disclosure.
  It should be noted that while the CEO and CFO believe that
  the registrant's disclosure controls and procedures provide a reasonable level
  of assurance that they are effective, they do not expect that the registrant's
  disclosure controls and procedures or internal control over financial
  reporting will prevent all errors and fraud. A control system, no matter how
  well conceived or operated, can provide only reasonable, not absolute,
  assurance that the objectives of the control system are met.
  (c) Changes in Internal Control Over Financial Reporting.
  During the fiscal year ended December 31, 2004, 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 required disclosure is included under the heading Audit
Committee Informationin the Annual Information Form included as part of
this form.
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 2004 and 2003, the services
provided in this category included due diligence reviews in connection with
acquisitions.
Tax Fees. Tax fees consist of fees for tax compliance
services, tax advice and tax planning. During fiscal 2004 and 2003, the services
provided in this category included assistance and advice in relation to the
preparation of corporate income tax returns.
All Other Fees. Not applicable.
Pre-Approval Policies and Procedures.

(a) All proposed services or the fees
  payable in connection with such services that have not already been
  pre-approved must be pre-approved by either the audit committee or pursuant to
  Delegated Authority (as defined below). Subject to the next paragraph, the
  audit committee has delegated authority to the chairman of the audit committee
  to pre-approve the provision of permitted services by PricewaterhouseCoopers
  LLP and not otherwise pre-approved by the full audit committee, including the
  fees and terms of the proposed services ("Delegated Authority"). All
  pre-approvals granted pursuant to Delegated Authority must be presented by the
  chairman to the full audit committee at its next meeting. The fees payable in
  connection with any particular service to be provided by
  PricewaterhouseCoopers LLP that has been pre-approved pursuant to Delegated

---

Authority may not exceed Cdn.$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", nil 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 Company does not have any off balance sheet arrangements.Tabular Disclosure of Contractual Obligations.

|(CDN$ millions)                                  |       | Payment due by period
|------------------------------------------------ | ----- | ---------------------
|                                                 |       |                      
|Contractual Obligations                          | Total | Less than            
|                                                 |       | 1 Year               
|                                                 |       |                      
|                                                 |       |                      
|Long-Term Debt Obligations                       | 432.3 | -                    
|                                                 |       |                      
|Capital (Finance) Lease Obligations              | -     | -                    
|Operating Lease Obligations                      | 16.3  | 2.4                  
|Purchase Obligations                             | -     | -                    
|Other Long-Term Liabilities Reflected
    on the | -     | -                    
|Registrant's Balance Sheet under
    Canadian    |       |                      
|GAAP                                             |       |                      
|Total                                            | 448.6 | 2.4                  

---

UNDERTAKING AND CONSENT TO SERVICE OF PROCESS
A. Undertaking.

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

The Company has previously filed a Form F-X in connection with
the class of securities in relation to which the obligation to file this report
arises.
Any change to the name or address of the agent for service of
process of the registrant shall be communicated promptly to the Securities and
Exchange Commission by an amendment to the Form F-X referencing the file number
of the relevant registration statement.
SIGNATURES

Pursuant to the requirements of the Exchange Act, the
registrant certifies that it meets all of the requirements for filing on Form
40-F and has duly caused this annual report to be signed on its behalf by the
undersigned, thereunto duly authorized, on March 24, 2005.

PROVIDENT ENERGY TRUSTBy: Provident Energy Ltd.By: /s/ Thomas W. BuchananName: Thomas W. BuchananTitle: President


---

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 (Calgary)                                 
|        |                                                                                     
|99.6    | Consent of
    PricewaterhouseCoopers LLP (Los Angeles)                             
|        |                                                                                     
|99.7    | Consent of KPMG LLP                                                                 
|        |                                                                                     
|99.8    | Consent of McDaniel &
    Associates Consultants Ltd.                               
|        |                                                                                     
|99.9    | Consent of Netherland
    Sewell & Associates Inc.                                  
|        |                                                                                     
|99.10   | Consent of Cawley
    Gillespie & Associates Inc.                                   
|        |                                                                                     

---