No securities regulatory authority has expressed an opinion about these securities and it is an offence to claim otherwise. This short form prospectus constitutes a public offering of these securities only in those jurisdictions where they may be lawfully offered for sale and therein only by persons permitted to sell such securities. These securities have not been and will not be registered under the United States Securities Act of 1933, as amended (the "1933 Act") or any state securities laws. Accordingly, these securities may not be offered or sold within the United States or to a U.S. person (as such term is defined in Regulation S under the 1933 Act) except in transactions exempt from the registration requirements of the 1933 Act and applicable state securities laws. This short form prospectus does not constitute an offer to sell or a solicitation of an offer to buy any of these securities within the United States of America.

	Short Form Prospectus
New Issue		June 28, 2004

$125,840,000
12,100,000 Trust Units

$ 50,000,000

8% Convertible Unsecured Subordinated Debentures

This prospectus qualifies the distribution of 12,100,000 trust units ("Trust Units") of Provident Energy Trust (the "Trust") at a price of $10.40 per Trust Unit and 50,000 8% convertible unsecured subordinated debentures (the "Debentures") of the Trust at a price of $1,000 per Debenture. The Debentures bear interest at an annual rate of 8% payable semi-annually on July 31 and January 31 in each year commencing January 31, 2005 and will mature on July 31, 2009 (the "Maturity Date"). See "Details of the Offering". Subscribers will have the option of subscribing for Debentures, Trust Units or a combination thereof at their discretion.

Debenture Conversion Privilege

Each Debenture will be convertible into Trust Units at the option of the holder of a Debenture at any time prior to the close of business on the earlier of the Maturity Date and the business day immediately preceding the date specified by the Trust for redemption of the Debentures, at a conversion price of $12.00 per Trust Unit, subject to adjustment in certain events.

The outstanding Trust Units are listed on the Toronto Stock Exchange (the "TSX") and the American Stock Exchange (the "AMEX"). The outstanding 10.5% convertible unsecured subordinated debentures of the Trust (the "10.5% Debentures") and the outstanding 8.75% convertible unsecured subordinated debentures of the Trust (the "8.75% Debentures") are listed on the TSX. The TSX has approved the listing of the Trust Units and the Debentures distributed under this short form prospectus and the Trust Units issuable on conversion of the Debentures. Listing of the Trust Units and Debentures distributed under this short form prospectus and the Trust Units issuable on conversion of the Debentures on the TSX will be subject to the Trust fulfilling all of the listing requirements of the TSX on or before September 15, 2004. The Trust has also applied to list the Trust Units distributed under this short form prospectus and the Trust Units issuable on conversion, redemption or at maturity of the Debentures on the AMEX. Listing will be subject to the Trust fulfilling all of the listing requirements of the AMEX. On June 25, 2004, the closing price of the Trust Units on the TSX and the AMEX was $10.43 per Trust Unit and U.S. $7.73 per Trust Unit, respectively, and the closing price of the 10.5% Debentures and 8.75% Debentures on the TSX was $106.75 and $103.50, respectively. The terms of the offering of the Trust Units and Debentures were determined by negotiation between Provident Energy Ltd. ("Provident"), on behalf of the Trust, and BMO Nesbitt Burns Inc., National Bank Financial Inc. and TD Securities Inc., on their own behalf and on behalf of Scotia Capital Inc., RBC Dominion Securities Inc., Canaccord Capital Corporation, Desjardins Securities Inc. and HSBC Securities (Canada) Inc. (collectively, the "Underwriters").

			Net Proceeds to
	Price to Public	Underwriters' Fee	the Trust(1)(2)
Per Trust Unit	$10.40	$0.52	$9.88
Total	$125,840,000	$6,292,000	$119,548,000
Per Debenture	$1,000	$40	$960
Total	$50,000,000	$2,000,000	$48,000,000
Total Trust Units and Debentures	$175,840,000	$8,292,000	$167,548,000

Notes:

1. Before deducting expenses of the offering, estimated to be $500,000, which will be paid from the general funds of the Trust.
2. The Trust has granted to the Underwriters an option (the "Underwriters' Option") to purchase an additional 1,000,000 Trust Units on the same terms as set forth above exercisable at any time until 48 hours prior to the date of closing, which additional Trust Units are qualified for distribution under this short form prospectus. If the Underwriters' Option is exercised in full, the total offering of Trust Units, the Underwriters' Fee and the Net Proceeds to the Trust in respect of the offering of Trust Units will be $136,240,000, $6,812,000 and $129,428,000, respectively.

The Underwriters, as principals, conditionally offer the Trust Units and Debentures, subject to prior sale, if, as and when issued by the Trust and accepted by the Underwriters in accordance with the conditions contained in the underwriting agreement referred to under "Plan of Distribution" and subject to approval of certain legal matters on behalf of the Trust by Macleod Dixon LLP and on behalf of the Underwriters by Stikeman Elliott LLP. Subscriptions will be received subject to rejection or allotment in whole or in part and the right is reserved to close the subscription books at any time without notice. Certificates representing the Trust Units will be available for delivery at closing, which is expected to occur on or about July 6, 2004 (the "Closing Date"). Certificates for the aggregate principal amount of the Debentures will be issued in registered form to The Canadian Depository for Securities Limited ("CDS") and will be deposited with CDS on the date of closing. No certificates evidencing the Debentures will be issued to purchasers, except in certain limited circumstances, and registration will be made in the depositary service of CDS. Purchasers of the Debentures will receive only a customer confirmation from the Underwriter or other registered dealer who is a CDS participant and from or through whom a beneficial interest in the Debentures is purchased. The Underwriters may effect transactions which stabilize or maintain the market price for the Trust Units or Debentures at levels other than those which otherwise might prevail in the open market. See "Plan of Distribution".

In the opinion of counsel, based on representations of Provident and the Trust as to certain factual matters, the Trust Units and Debentures offered hereunder will, on the date of issue, be qualified investments under the Income Tax Act (Canada) (the "Tax Act") and the regulations thereunder for trusts governed by registered retirement savings plans, registered retirement income funds, deferred profit sharing plans (other than, in the case of the Debentures, a deferred profit sharing plan for the benefit of employees of the Trust) and registered education savings plans and will not be foreign property for purposes of the Tax Act. See "Eligibility for Investment".

The interest coverage ratio in respect of the Debentures for the twelve month period ended December 31, 2003 and the twelve month period ended March 31, 2004, is less than 1:1. Interest coverage ratios from cash flow (defined as funds from operations before working capital changes) for these periods exceed 1:1. See "Interest Coverage".

The Trust has declared a distribution of $0.12 per Trust Unit to be payable on July 15, 2004 to holders of Trust Units ("Unitholders") of record on June 18, 2004. Purchasers of Trust Units pursuant to the offering will not be eligible to receive the distribution payable on July 15, 2004. It is anticipated that the offering will close prior to July 20, 2004, which is the record date for the distribution by the Trust to Unitholders payable on August 13, 2004. Accordingly, provided the offering closes prior to July 20, 2004, subscribers who complete their purchase of Trust Units from the Underwriters and continue to be the registered holder of such Trust Units on July 20, 2004 will be eligible to participate in the distribution of the Trust payable on August 13, 2004. See "Record of Cash Distributions".

Each of BMO Nesbitt Burns Inc., National Bank Financial Inc., TD Securities Inc. and Scotia Capital Inc. is an indirect wholly-owned subsidiary of a Canadian chartered bank which is a lender to the Trust and Provident. Consequently, the Trust may be considered to be a connected issuer of each of these Underwriters under applicable Canadian securities laws. See "Relationship Among the Trust, Provident and Certain Underwriters" and "Use of Proceeds".

There is currently no market through which the Debentures may be sold and purchasers may not be able to resell the Debentures purchased under this short form prospectus.

The Trust Units and Debentures 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.

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TABLE OF CONTENTS

	Page
NOTE REGARDING FORWARD LOOKING STATEMENTS	1
SELECTED ABBREVIATIONS AND DEFINITIONS	2
PRESENTATION OF OIL AND GAS RESERVES AND PRODUCTION INFORMATION	2
DOCUMENTS INCORPORATED BY REFERENCE	3
SUMMARY	5
PROVIDENT ENERGY TRUST	7
RECENT DEVELOPMENTS	8
INFORMATION CONCERNING THE BREITBURN PROPERTIES	10
EFFECT OF THE BREITBURN ACQUISITION ON THE TRUST	18
DETAILS OF THE OFFERING	19
INTEREST COVERAGE	25
PLAN OF DISTRIBUTION	26
RISK FACTORS	27
CAPITALIZATION OF THE TRUST	28
PRICE RANGE AND TRADING VOLUME OF THE TRUST UNITS	29
RECORD OF CASH DISTRIBUTIONS	30
USE OF PROCEEDS	30
RELATIONSHIP AMONG THE TRUST, PROVIDENT AND CERTAIN UNDERWRITERS	31
CANADIAN FEDERAL INCOME TAX CONSIDERATIONS	31
ELIGIBILITY FOR INVESTMENT	35
LEGAL MATTERS	35
AUDITORS, TRANSFER AGENT AND REGISTRAR	36
INTERESTS OF EXPERTS	36
CONSENTS	36
PURCHASERS' STATUTORY RIGHTS	37
SCHEDULE A FINANCIAL STATEMENTS OF BREITBURN ENERGY COMPANY LLC	A-1
SCHEDULE B UNAUDITED PRO FORMA CONSOLIDATED FINANCIAL STATEMENTS	B-1
CERTIFICATE OF PROVIDENT ENERGY TRUST	C-1
CERTIFICATE OF THE UNDERWRITERS	C-2

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NOTE REGARDING FORWARD LOOKING STATEMENTS

This short form prospectus 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 short form prospectus 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 short form prospectus 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;

• 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 Provident's natural gas midstream and NGL processing business;

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

• the nature of contractual arrangements with third parties in respect of Provident's natural gas midstream and NGL processing business.

Although the Trust believes that the expectations reflected in the forward-looking statements are reasonable, there can be no assurance that such expectations will prove to be correct. Neither the Trust nor the Underwriters can guarantee future results, levels of activity, performance, or achievements. Moreover, neither the Trust, the Underwriters 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 short form prospectus and the documents incorporated by reference herein include, but are not limited to:

• general economic conditions in Canada, the United States and globally;

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

• uncertainties associated with estimating reserves;

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

• interest payable on notes issued in connection with acquisitions;

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• governmental regulation in North America of the oil and gas industry, including income tax and environmental regulation;

• fluctuation in foreign exchange or interest rates;

• stock market volatility and market valuations;

• the need to obtain required approvals from regulatory authorities;

• unanticipated operating events which can reduce production or cause production to be shut-in or delayed;

• failure to realize the anticipated benefits of acquisitions;

• 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 short form prospectus and the AIF (as defined herein).

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 short form prospectus and the documents incorporated by reference herein are expressly qualified by this cautionary statement. Neither the Trust nor the Underwriters are under any duty to update any of the forward-looking statements after the date of this short form prospectus to conform such statements to actual results or to changes in the Trust's expectations.

SELECTED ABBREVIATIONS AND DEFINITIONS

In this short form prospectus, the abbreviations and terms set forth below have the meanings indicated:

"bbl" means one barrel. "bcf" means one billion cubic feet. "boe/d" or "boed" means one barrel of oil equivalent per day. "mboe" means one thousand barrels of oil equivalent. "mbbls" means one thousand barrels. "mcf" means one thousand cubic feet. "mcf/d" means one thousand cubic feet per day. "mmcf" means one million cubic feet. "bbls/d", "b/d", or "bpd" means barrels per day. "boe" means barrels of oil equivalent. A barrel of oil equivalent is determined by converting a volume of natural gas to barrels using the ratio of six mcf to one barrel. Boes may be misleading, particularly if used in isolation. The boe conversion ratio of 6 mcf:1 bbl is based on an energy equivalency method primarily applicable at the burner tip and does not represent a value equivalency at the wellhead. "mmbbls" means one million barrels. "mmcf/d" means one million cubic feet per day. "NGL" means natural gas liquids.    

In this short form prospectus, all dollar amounts are stated in Canadian dollars except where otherwise indicated. All dollar amounts set forth in Schedule A of this short form prospectus are stated in U.S. dollars except where otherwise indicated.

PRESENTATION OF OIL AND GAS RESERVES AND PRODUCTION INFORMATION

All oil and natural gas information contained in this short form prospectus, including the documents incorporated by reference, has been prepared and presented in accordance with 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 short form prospectus. 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 BOEs. BOEs 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.

All operational information relating to the Breitburn Properties (as defined herein) contained in this short form prospectus is based on information provided to the Trust by third parties. Netherland, Sewell & Associates, Inc. ("NSA") and Cawley, Gillespie & Associates, Inc. ("CGA"), independent petroleum engineers, have prepared the oil and gas reserves reports in respect of the Breitburn Properties.

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DOCUMENTS INCORPORATED BY REFERENCE

Information has been incorporated by reference in this short form prospectus from documents filed with securities commissions or similar authorities in Canada. Copies of the documents incorporated herein by reference may be obtained on request without charge from the President or Chief Executive Officer of Provident at 700, 112 - 4th Avenue S.W., Calgary, Alberta T2P 0H3, telephone (403) 296-2233. For the purpose of the Province of Québec, this simplified prospectus contains information to be completed by consulting the permanent information record. A copy of the permanent information record may be obtained from the President or Chief Executive Officer of Provident at the above-mentioned address and telephone number. Copies of the documents incorporated herein by reference are also available at www.sedar.com.

The following documents of the Trust, filed with the various provincial securities commissions or similar authorities in Canada, are specifically incorporated into and form an integral part of this short form prospectus:

1. the Renewal Annual Information Form of the Trust dated April 23, 2004 (the "AIF") including the financial statements of the Redwater Natural Gas Liquids Processing System of Williams Energy (Canada), Inc., together with the notes thereto and the auditors' report thereon attached as Schedule A to the AIF;
    

2. the unaudited comparative consolidated financial statements of the Trust and management's discussion and analysis of the financial condition and operations of the Trust as at and for the three months ended March 31, 2004;
    

3. the audited comparative consolidated financial statements of the Trust and management's discussion and analysis of the financial condition and operations of the Trust for the year ended December 31, 2003;
    

4. the Proxy Statement and Information Circular dated April 9, 2004 in connection with the annual and special meeting of Unitholders of the Trust held on May 10, 2004 (excluding those portions thereof which, pursuant to National Instrument 44-101 of the Canadian Securities Administrators, are not required to be incorporated by reference herein);
    

5. the material change report of the Trust dated April 14, 2004 in respect of the entering into of an arrangement agreement dated April 6, 2004 among the Trust, Provident, Olympia Energy Inc. ("Olympia") and 1101130 Alberta Ltd. (now Accrete Energy Inc.) ("Accrete");
    

6. the material change report of the Trust dated April 14, 2004 in respect of the entering into of an arrangement agreement dated April 6, 2004 among the Trust, Provident, Viracocha Energy Inc. ("Viracocha") and 1100974 Alberta Inc. (now Chamaelo Energy Inc.) ("Chamaelo");
    

7. the material change report of the Trust dated June 14, 2004 in respect of the completion of the acquisition of Olympia and the effect of such acquisition on the Trust;
    

8. the material change report of the Trust dated June 14, 2004 in respect of the completion of the acquisition of Viracocha and the effect of such acquisition on the Trust;
    

9. the material change report of the Trust dated June 24, 2004 in respect of the completion of the Breitburn Acquisition (as defined herein) and the effect of such acquisition on the Trust;
    

10. the business acquisition report of the Trust dated June 16, 2004 in respect of the acquisition of Olympia (excluding the pro forma financial statements set forth in Schedule A thereto) including the audited annual consolidated financial statements of Olympia for the year ended December 31, 2003 attached as Schedule B thereto and the unaudited comparative consolidated interim financial statements of Olympia for the three month period ended March 31, 2004 attached as Schedule C thereto; and
     
11. the business acquisition report of the Trust dated June 16, 2004 in respect of the acquisition of Viracocha (excluding the pro forma financial statements set forth in Schedule A thereto) including the audited annual consolidated financial statements of Viracocha for the year ended December 31, 2003 attached as Schedule B thereto and the unaudited comparative consolidated interim

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financial statements of Viracocha for the three month period ended March 31, 2004 attached as Schedule C thereto.

Any of the following documents, if filed by the Trust with the provincial securities commissions or similar authorities in Canada after the date of this short form prospectus and before the termination of the offering, are deemed to be incorporated by reference in this short form prospectus:

1. material change reports (except confidential material change reports);
2. comparative interim financial statements;
3. comparative financial statements for the Trust's most recently completed financial year, together with the accompanying report of the auditor; and

4. information circulars (excluding the disclosure in an information circular relating to the downward repricing of options or stock appreciation rights, the composition of the Trust's compensation committee and its report on executive compensation, the performance graph for the Trust Units and the Trust's corporate governance practices).

Documents are not incorporated by reference to the extent their contents are modified or superseded by a statement contained in this short form prospectus or in any other subsequently filed document that is also incorporated by reference in this short form prospectus.

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SUMMARY The following is a summary of certain information contained in this short form prospectus and is qualified in its entirety by, and should be read in conjunction with, the more detailed information contained elsewhere in this short form prospectus. The Trust The Trust is an open-end unincorporated investment trust created under the laws of Alberta and created pursuant to a trust indenture dated as of January 25, 2001, as amended (the "Trust Indenture"). The beneficiaries of the Trust are the Unitholders. Cash flow from the petroleum and natural gas properties and the natural gas midstream and NGL processing business is distributed from Provident to the Trust by way of royalty payments and interest and principal repayments on notes issued by Provident to the Trust from time to time. Distributable cash generated by the royalties, interest and principal repayments is distributed monthly to Unitholders. The Breitburn Acquisition On June 15, 2004, the Trust entered into an agreement and plan of merger among Breitburn Energy Company LLC ("Breitburn"), a California limited liability company, Pro GP Corp., a Delaware corporation and wholly-owned indirect subsidiary of the Trust, Pro LP Corp., a Delaware corporation and wholly-owned indirect subsidiary of the Trust and BB Merger 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 (the "Breitburn Acquisition"), 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 Breitburn, subject to certain adjustments. The Breitburn Acquisition was completed on June 15, 2004 and resulted in the Trust indirectly holding 92% of the outstanding partnership interests of Breitburn Energy Company L.P., a Delaware limited partnership. The remaining 8% of the outstanding partnership interests of Breitburn Energy Company L.P. were retained by Breitburn's co-founders and co-chief executive officers for an aggregate purchase price of $13.7 million. Breitburn Energy Company 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 Offering
Issue:	12,100,000 Trust Units $50,000,000 aggregate principal amount of Debentures.
Total Amount of Offering:	$175,840,000
Price:	$10.40 per Trust Unit $1,000 per Debenture
Use of Proceeds:	The net proceeds of the offering of Trust Units and Debentures will be used by the Trust to repay indebtedness of Provident under its credit facilities incurred to fund the Breitburn Acquisition, to fund the Trust's capital expenditure program and for general corporate purposes.
Debentures
Maturity:	The Maturity Date for the Debentures will be July 31, 2009.
Interest:	8% per annum payable semi-annually in arrears on July 31 and January 31 in each year, commencing January 31, 2005. The first interest payment on January 31, 2005 will include interest accrued from the closing date of the offering to but excluding January 31,

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	2005.
Conversion:	The Debentures will be convertible into fully paid and non-assessable Trust Units at the option of the holder at any time prior to the close of business on the earlier of the Maturity Date and the business day immediately preceding the date specified by the Trust for redemption of the Debentures at a conversion price of $12.00 per Trust Unit, being a conversion rate of 83.3333 Trust Units per $1,000 principal amount of Debentures, subject to adjustment as provided in the Indenture (as defined herein). Holders converting their Debentures will receive all accrued and unpaid interest thereon.
Redemption:	The Debentures will be convertible into fully paid and non-assessable Trust Units at the option of the holder at any time prior to the close of business on the earlier of the Maturity Date and the business day immediately preceding the date specified by the Trust for redemption of the Debentures at a conversion price of $12.00 per Trust Unit, being a conversion rate of 83.3333 Trust Units per $1,000 principal amount of Debentures, subject to adjustment as provided in the Indenture (as defined herein). Holders converting their Debentures will receive all accrued and unpaid interest thereon.
Payment upon Redemption or Maturity:	The Debentures will not be redeemable on or before July 31, 2007. After July 31, 2007 and prior to maturity, the Debentures may be redeemed in whole or in part from time to time at the option of the Trust on not more than 60 days and not less than 30 days notice, at a price of $1,050 per Debenture after July 31, 2007 until July 31, 2008 and at a price of $1,025 per Debenture thereafter until maturity (each a "Redemption Price"), in each case, plus accrued and unpaid interest thereon, if any.
Change of Control:	On redemption or at the Maturity Date, the Trust may, at its option on not more than 60 days and not less than 40 days prior notice and subject to regulatory approval, elect to satisfy its obligation to pay the applicable Redemption Price or the principal amount of the Debentures by issuing and delivering that number of freely tradeable Trust Units obtained by dividing the aggregate Redemption Price of the outstanding Debentures which are to be redeemed, or the principal amount of outstanding Debentures which have matured, as the case may be, by 95% of the weighted average trading price of the Trust Units on the TSX for the 20 consecutive trading days ending on the fifth trading day preceding the date fixed for redemption or the Maturity Date, as the case may be. Any accrued and unpaid interest thereon will be paid in cash.
Subordination:	The payment of the principal of, and interest on, the Debentures will be subordinated in right of payment, as set forth in the Indenture, to the prior payment in full of all Senior Indebtedness (as defined herein) of the Trust. The Debentures will also be effectively subordinate to claims of creditors of the Trust's subsidiaries except to the extent the Trust is a creditor of such subsidiary ranking at least pari passu with such other creditors. The Debentures will not limit the ability of the Trust to incur additional indebtedness, including indebtedness that ranks senior to the Debentures, or from mortgaging, pledging or charging its properties to secure any indebtedness.

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PROVIDENT ENERGY TRUST

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 is a corporation the common shares of which are wholly-owned by the Trust. Provident was incorporated under the Business Corporations Act (Alberta) (the "ABCA") on January 19, 2001 and was amalgamated with Founders Energy Ltd. ("Founders") pursuant to a plan of arrangement involving the Trust, Provident and Founders effective March 6, 2001. Provident subsequently amalgamated with Maxx Petroleum Ltd. ("Maxx") effective May 25, 2001 pursuant to a plan of arrangement involving the Trust, Provident and Maxx. Provident was also amalgamated with Richland Petroleum Corporation ("Richland") effective January 16, 2002 pursuant to a plan of arrangement involving the Trust, Provident and Richland. Provident was amalgamated with Provident Management Corporation (the "Manager") pursuant to a management internalization transaction involving the Trust, Provident, the Manager and the shareholders of the Manager effective January 17, 2003. The head and principal offices of Provident are located at 700, 112 4th Avenue S.W., Calgary, Alberta T2P 0H3. The registered office of Provident is 3700, 400 - 3rd Avenue S.W., Calgary, Alberta T2P 4H2. Provident owns all of the common shares of the following four 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 ("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. ("Provident Acquisitions") is a limited partnership registered in the Province of Alberta. Provident Acquisitions was formed pursuant to a limited partnership agreement dated April 19, 2002. The general partner of Provident Acquisitions is Provident which holds a 1% interest in the partnership. Holdings Trust is the limited partner of Provident Acquisitions with a 99% interest in the partnership. The head and principal offices of Provident Acquisitions are located at 700, 112 4th Avenue S.W. Calgary, Alberta T2P 0H3. The registered office of Provident Acquisitions is 3700, 400 3rd Avenue S.W. Calgary, Alberta T2P 4H2.

Provident Acquisitions Inc.

Provident Acquisitions Inc. ("PAI") 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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RECENT DEVELOPMENTS

The Breitburn Acquisition

Overview of the Breitburn Acquisition

On June 15, 2004, the Trust entered into an agreement and plan of merger (the "Breitburn Agreement") among Breitburn Energy Company LLC ("Breitburn"), a California limited liability company, Pro GP Corp., a Delaware corporation and wholly-owned indirect subsidiary of the Trust ("Pro GP"), Pro LP Corp., a Delaware corporation and wholly-owned indirect subsidiary of the Trust ("Pro LP") and BB Merger LLC, a Delaware limited liability company and wholly-owned indirect subsidiary of the Trust ("Acquisition LLC"), pursuant to which the Trust acquired all of the issued and outstanding shares of Breitburn (the "Breitburn Acquisition"), 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 Breitburn, subject to certain adjustments. Under the terms of the Breitburn Agreement, Breitburn and Acquisition LLC have merged and Breitburn has been converted into Breitburn Energy Company 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 Energy Company L.P., a limited partnership. The remaining 8% of the outstanding partnership interests of Breitburn Energy Company L.P. were retained by Breitburn's co-founders and co-chief executive officers for an aggregate purchase price of $13.7 million.

Breitburn Energy Company 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 "Breitburn Properties").

Financing of the Breitburn Acquisition

The Trust intends to use a portion of the net proceeds from the offering to repay indebtedness under Provident's credit facilities which indebtedness was incurred to fund the Breitburn Acquisition. See "Use of Proceeds".

Post-Closing Organizational Structure

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, collectively hold 92% of the outstanding partnership interests in Breitburn Energy Company L.P., a Delaware limited partnership, which continues to hold the Breitburn Properties. Breitburn Energy Corporation, a California corporation, holds 8% of the outstanding partnership interests of Breitburn Energy Company L.P.

Breitburn Energy Company LP will continue 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 cofounders and co-chief executive officers will serve as directors of Pro GP, the managing partner of Breitburn Energy Company L.P. Breitburn Energy Company 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 Energy Company L.P. The following diagram sets out the Trust's organizational structure relating only to the completion of the Breitburn Acquisition.

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Acquisition of Olympia Energy Inc.

On June 1, 2004, the Trust and Provident completed the acquisition of all of the issued and outstanding common shares of Olympia pursuant to a plan of arrangement (the "Olympia Plan of Arrangement") in accordance with an arrangement agreement dated as of April 6, 2004 among the Trust, Provident, Olympia and 1101130 Alberta Ltd. (now Accrete).

In accordance with the Olympia 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 Plan of Arrangement, (ii) 0.345 of an exchangeable share of Provident (the "Exchangeable Shares"), or (iii) a combination of Trust Units and Exchangeable Shares. Under the Plan of Arrangement, the number of 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.

Upon completion of the Olympia Plan of Arrangement, an aggregate of 13,385,579 Trust Units and 1,325,000 Exchangeable Shares were issued to the former Olympia shareholders.

Additional information concerning the effects of the acquisition of Olympia on the Trust and the information presented in the Trust's Statement of Reserve Data and Other Oil and Gas Information in Form NI 51-101F1 contained in the AIF is included in the material change report of the Trust dated June 14, 2004 incorporated by reference herein. The audited consolidated annual financial statements of Olympia for the year ended December 31, 2003 and the unaudited consolidated interim financial statements of Olympia for the three month period ended March 31, 2004 are contained in the business acquisition report of the Trust dated June 16, 2004 incorporated by reference herein.

Acquisition of Viracocha Energy Inc.

On June 1, 2004, the Trust and Provident completed the acquisition of all of the issued and outstanding common shares of Viracocha pursuant to a plan of arrangement (the "Viracocha Plan of Arrangement") in accordance with an arrangement agreement dated as of April 6, 2004 among the Trust, Provident, Viracocha and 1100974 Alberta Inc. (now Chamaelo).

In accordance with the Viracocha 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 Viracocha Plan of Arrangement, (ii) 0.248 of an Exchangeable Share of Provident, or (iii) a combination of Trust Units and Exchangeable Shares. Under the Plan of Arrangement, the number of 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.

- 9 -

Upon completion of the Viracocha Plan of Arrangement, an aggregate of 12,758,386 Trust Units and 1,325,000 Exchangeable Shares were issued to the former Viracocha shareholders.

Additional information concerning the effects of the acquisition of Viracocha on the Trust and the information presented in the Trust's Statement of Reserve Data and Other Oil and Gas Information in Form NI 51-101F1 contained in the AIF is included in the material change report of the Trust dated June 14, 2004 incorporated by reference herein. The audited consolidated annual financial statements of Viracocha for the year ended December 31, 2003 and the unaudited consolidated interim financial statements of Viracocha for the three month period ended March 31, 2004 are contained in the business acquisition report of the Trust dated June 16, 2004 incorporated by reference herein.

Production for the Three Months Ended March 31, 2004

For the three months ended March 31, 2004, Provident's production averaged 24,326 boe/d comprised of 7,095 bbls/d of light crude oil and NGLs, 6,588 bbls/d of 15°API heavy oil and 63,859 mcf/d of natural gas (excluding production attributable to Olympia and Viracocha).

Monthly Cash Distribution

On June 9, 2004, the Trust announced that it would pay a cash distribution of $0.12 per Trust Unit on July 15, 2004 to Unitholders of record on June 18, 2004. The distribution level is reflective of cash flow and payout ratio expectations for 2004 based on the current commodity price environment and exchange rate environment.

Management's Discussion and Analysis of Operating Results

The following information is intended to restate certain information set forth in management's discussion and analysis of operating results of the Trust for the first quarter ended March 31, 2004: (i) at March 31, 2004, the Trust recorded a non-hedging derivative instrument payable of $40.6 million, all of which was short-term, and not $35.4 million short-term and $5.2 million long-term as previously reported, (ii) the oil and gas production business segment had a net loss of $7.0 million and not $14.5 million as previously reported, (iii) the midstream business unit had a net income of $4.7 million and not $4.4 million as previously reported, and (iv) the first quarter 2004 future net income tax recovery was $14.549 million and not $10.5 million as previously reported. All amounts reported in the Trust's financial statements for the three month period ended March 31, 2004 remain unchanged.

Status of Unitholder Limited Liability Legislation

In May 2004, the Alberta legislature passed Bill 34, which would enact a new statute, to be called the Income Trusts Liability Act, to create a statutory limitation on the liability of unitholders of Alberta income trusts such as the Trust. The Bill received Royal Assent on May 19, 2004 and will come into force on Proclamation. The legislation is intended to protect unitholders of income funds and royalty trusts from the legal uncertainties regarding the potential liability of unitholders. See "Risk Factors - General Risk Factors - Unitholder Limited Liability" in the AIF.

INFORMATION CONCERNING THE BREITBURN PROPERTIES

Description of the Breitburn Properties

The following is a description of the principal oil and natural gas properties to be acquired by the Trust upon completion of the Breitburn Acquisition.

Beverly Hills East (West Pico Unit)

Beverley Hills East 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 1965 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 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

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26 producing wells is approximately 950 boe per day of light to medium crude oil (approximately 28 API) and associated gas. Remaining Breitburn interest proved plus probable reserves are estimated by NSA to be 16.8 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

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 83 producing wells is approximately 1,700 barrels per day of primarily light crude oil (approximately 35 API). Remaining Breitburn interest proved plus probable reserves are estimated by NSA to be 11.4 million barrels of oil equivalent. Development potential includes expansion of waterflood operations, infill drilling, recompletions and returning shut-in wells to production.

Oil and Natural Gas Reserves

The reserves attributable to the Breitburn Properties have been evaluated in accordance with NI 51-101 by NSA and CGA, independent petroleum engineers, in reports dated June 918, 2004 and June 7, 2004, respectively and effective December 31, 2003. The following is a summary, as at December 31, 2003 of the crude oil, NGLs and natural gas reserves attributed by such reports to the Breitburn Properties and the estimated net present values of future net revenues associated with such reserves, based on forecast and constant 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 forecast and constant price evaluations is set forth in the notes to the tables. Upon completion of the Breitburn Acquisition, Provident will indirectly hold 92% of the outstanding partnership interests in Breitburn Energy Company L.P. which will hold the Breitburn Properties. Breitburn Energy Corporation will continue to hold 8% of the outstanding partnership interests in Breitburn Energy Company L.P.

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 Breitburn's reserves. There is no assurance that the forecast price and cost assumptions contained in the NSA and CGA 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. The actual oil and natural gas reserves and future production on the Breitburn Properties will be greater or less than those calculated.

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

	Light and	Medium	Heavy	Oil	Natural	Gas	Natural	Gas
	Oil						Liquids
	Gross(1)	Net(1)	Gross(1)	Net(1)	Gross(1)	Net(1)	Gross(1)	Net(1)
	(mbbl)	(mbbl)	(mbbl)	(mbbl)	(mmcf)	(mmcf)	(mbbl)	(mbbl)
Proved Developed Producing(2)(6)	22,122	20,064	-	-	6,995	5,957	175	158
Proved Developed Non-Producing(2)(7)	4,689	4,300	-	-	1,420	1,202	-	-
Proved Undeveloped(2)(8)	10,307	8,777	-	-	11,684	9,629	821	676
Total Proved(2)	37,118	33,142	-	-	20,099	16,789	996	834

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

	Before Income Taxes		After Income	Taxes(11)
	Discounted At		Discounted At
	0%	10%	0%	10%
	(MM$)	(MM$)	(MM$)	(MM$)
Proved Developed Producing(2)(6)	297.4	139.6	273.8	128.1
Proved Developed Non-Producing(2)(7)	82.0	40.4	37.3	15.8
Proved Undeveloped(2)(8)	293.7	142.5	196.7	98.0
Total Proved(2)	673.1	322.4	507.8	241.9

BREITBURN
TOTAL FUTURE NET REVENUE
(UNDISCOUNTED)
BASED ON CONSTANT PRICES AND COSTS(9)
						Future		Future
					Abandonment	Net Revenue		Net
					and	Before		Revenue
			Operating	Development	Reclamation	Income	Income	After Income
	Revenue	Royalties	Costs	Costs	Costs	Taxes	Taxes(11)	Taxes(11)
	(MM$)	(MM$)	(MM$)	(MM$)	(MM$)	(MM$)	(MM$)	(MM$)
Total Proved(2)	1,631.1	237.7	570.7	139.0	10.6	673.1	165.3	507.8

BREITBURN
FUTURE NET REVENUE BY PRODUCTION GROUP
BASED UPON CONSTANT PRICES AND COSTS(9)
		Future Net Revenue Before Income
		Taxes (Discounted at 10%/Year)
	Production Group	(M$)
Total Proved(2)	Light and medium crude oil	317,241
	Heavy oil	-
	Associated and non-associated gas	5,167

BREITBURN
OIL AND GAS RESERVES
BASED ON FORECAST PRICES AND COSTS(10)
							Natural	Gas
	Light and	Medium Oil	Heavy	Oil	Natural	Gas	Liquids
	Gross(1)	Net(1)	Gross(1)	Net(1)	Gross(1)	Net(1)	Gross(1)	Net(1)
	(mbbl)	(mbbl)	(mbbl)	(mbbl)	(mmcf)	(mmcf)	(mbbl)	(mbbl)
Proved Developed Producing(2)(6)	15,197	13,845	-	-	5,304	4,512	116	104
Proved Developed Non-Producing(2)(7)	3,684	3,384	-	-	1,068	910	-	-
Proved Undeveloped(2)(8)	9,321	7,928	-	-	11,000	9,066	812	668
Total Proved(2)	28,202	25,158	-	-	17,372	14,489	928	772
Total Probable(3)	6,477	5,795	-	-	4,050	3,374	258	213
Total Proved Plus Probable(2)(3)	34,679	30,953	-	-	21,422	17,863	1,186	985

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BREITBURN
NET PRESENT VALUES OF FUTURE NET REVENUE
BASED ON FORECAST PRICES AND COSTS(10)
	Before Deducting Income Taxes					After Deducting Income Taxes(11)
	Discounted At(1)					Discounted At(1)
	0%	5%	10%	15%	20%	0%	5%	10%	15%	20%
	(MM)	(MM)	(MM)	(MM)	(MM)	(MM)	(MM)	(MM)	(MM)	(MM)
Proved Developed Producing(2)(6)	116	85	67	56	49	108	80	63	53	47
Proved Developed Non-Producing(2)(7)	49	33	25	19	15	42	29	21	16	13
Proved Undeveloped(2)(8)	194	121	87	67	53	162	101	72	55	43
Total Proved(2)	359	239	179	142	117	312	209	156	124	103
Total Probable(3)	166	81	50	35	27	108	52	32	22	16
Total Proved Plus Probable(2)(3)	525	320	229	178	144	420	261	188	146	119

BREITBURN
TOTAL FUTURE NET REVENUE
(UNDISCOUNTED)
BASED ON FORECAST PRICES AND COSTS(10)
						Future		Future
					Abandonment	Net Revenue		Net
					and	Before		Revenue
			Operating	Development	Reclamation	Income	Income	After Income
	Revenue	Royalties	Costs	Costs	Costs	Taxes	Taxes(11)	Taxes(11)
	(MM$)	(MM$)	(MM$)	(MM$)	(MM$)	(MM$)	(MM$)	(MM$)
Total Proved(2)	1,111.2	161.8	456.7	116.3	18.7	358.5	46.6	312.0
Total Proved Plus
Probable(2)(3)	1,400.0	206.0	511.4	139.4	18.7	524.6	104.6	420.0

BREITBURN
FUTURE NET REVENUE BY PRODUCTION GROUP
BASED ON FORECAST PRICES AND COSTS(10)
		Future Net Revenue Before Income
		Taxes (Discounted at 10%/Year)
	Production Group	(M$)
Total Proved(2)	Light and medium crude oil	175,772
	Heavy oil	-
	Associated and non-associated gas	3,068

Notes:

1. "Gross Reserves" are Breitburn's working interest (operated or non-operated) share before deducting of royalties and without including any royalty interests of Breitburn. "Net Reserves" are Breitburn's working interest (operated or non-operated) share after deduction of royalty obligations, plus Breitburn's royalty interests in reserves. Reserves and values reported are based on 100% of the interests of Breitburn in the properties as at December 31, 2003.

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 in the NSA and CGA reports for Breitburn were as follows: Nymex West Texas Intermediate Crude $Cdn. 43.36/bbl; Henry Hub Natural Gas $Cdn 7.96/mmbtu.

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10. The pricing assumptions used in the NSA and CGA reports for Breitburn with respect to net present values of future net revenue (forecast) as well as the exchange rates and inflation rates used for operating and capital costs are set forth below in the McDaniel & Associates Consultants Ltd. Summary of Price Forecasts. NSA and CGA are independent qualified reserves evaluators appointed pursuant to NI 51-101.

11. After tax forecasts for the Breitburn properties are based on U.S taxes.

McDaniel & Associates Consultants Ltd.
Summary of Price Forecasts
January 1, 2004

						Natural Gas
	Light and Medium Crude Oil			Heavy Oil	Natural Gas	Liquids	Inflation Rate	Exchange Rate
		Edmonton	Cromer
	WTI Cushing	Light	Medium 290	Hardisty	AECO Gas	Edmonton
	Oklahoma	400 API	API	Heavy 120 API	Price	NGL Mix
	($US/bbl)	($Cdn/bbl)	($Cdn/bbl)	($Cdn/bbl)	($Cdn/mcf)	($Cdn/bbl)	%/year	$US/$Cdn
Year
Forecast
2004	29.00	37.70	32.20	22.70	5.50	27.90	2.0	0.750
2005	26.50	34.30	29.71	21.55	5.19	25.50	2.0	0.750
2006	25.50	33.00	28.84	21.56	4.87	24.50	2.0	0.750
2007	25.00	32.30	28.06	20.63	4.68	23.80	2.0	0.750
2008	25.00	32.30	27.97	20.39	4.53	23.70	2.0	0.750
2009	25.50	32.90	28.48	20.76	4.57	24.10	2.0	0.750
2010	26.00	33.50	29.00	21.11	4.60	24.50	2.0	0.750
2011	26.50	34.20	29.61	21.56	4.69	25.00	2.0	0.750
2012	27.00	34.80	30.11	21.91	4.78	25.40	2.0	0.750
2013	27.50	35.50	30.72	22.35	4.87	26.00	2.0	0.750
2014	28.10	36.20	31.32	22.79	4.97	26.50	2.0	0.750
2015	28.70	37.00	32.03	23.32	5.08	27.10	2.0	0.750
2016	29.30	37.80	32.73	23.85	5.19	27.60	2.0	0.750
2017	29.90	38.60	33.43	24.37	5.29	28.20	2.0	0.750
2018	30.50	39.30	34.02	24.79	5.40	28.70	2.0	0.750
2019	31.10	40.10	34.72	25.30	5.51	29.30	2.0	0.750
2020	31.70	40.90	35.41	25.80	5.61	29.90	2.0	0.750
2021	32.30	41.70	36.10	26.30	5.72	30.50	2.0	0.750
2022	32.90	42.40	36.69	26.69	5.82	31.00	2.0	0.750
2023	33.60	43.30	37.47	27.28	5.95	31.60	2.0	0.750
Thereafter	33.60	43.30	37.47	27.28	5.95	31.60	0.0	0.750

Future Development Costs

The following table sets out the future development costs for undeveloped reserves in respect of the Breitburn Properties.

			Total Proved Plus
	Total Proved	Total Proved	Probable
	Estimated Using	Estimated Using	Estimated Using
	Constant Prices	Forecast Prices	Forecast Prices
	and Costs	and Costs	and Costs
	(M$)	(M$)	(M$)
2004	14,882	14,979	15,041
2005	21,306	21,655	26,879
2006	6,442	6,268	9,083
2007	4,007	4,051	5,328
2008	3,981	4,028	4,219
Total for all years undiscounted	138,999	116,324	139,406
Total for all years discounted at 10%	67,479	63,537	75,150

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.

Abandonment and Reclamation Costs

Facility abandonment and well abandonment costs were estimated for each field by Breitburn. The net well count for active and idle wells to be abandoned is 481.

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The expected abandonment costs associated with the Breitburn Properties 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.As shown below, no abandonment costs are anticipated in the next three years. Well and facility abandonment costs are scheduled at the end of the economic life of each field. The total undiscounted abandonment costs are $10,559,000 undiscounted and $496,000 discounted at 10%.

	Abandonment Costs
	M$
2004	-
2005	-
2006	-
3 year Subtotal	-
Total Undiscounted	10,559
Total Discounted @ 10%	496

Oil and Gas Wells

The following table sets forth the number and status of wells in which the Trust will acquire a working interest pursuant to the Breitburn Acquisition.

	Oil Wells				Natural Gas Wells
	Producing		Non-Producing(1)		Producing		Non-Producing(1)
	Gross(2)	Net	Gross	Net	Gross(2)	Net	Gross	Net
California
Beverly Hills East	26	23.5	32	31.5	-	-	-	-
Santa Fe Springs	83	82.5	155	154.4	-	-	-	-
Other	191	126.7	84	59.4	-	-	1	1
Total California	300	232.7	271	245.3	-	-	1	1
Wyoming	6	1.9			-	-	-	-
	306	234.6	271	245.3	-	-	1	1

Notes:

1. Non-Producing wells means wells which have encountered and are capable of producing crude oil or natural gas but which are not producing due to lack of available transportation facilities, available markets or other reasons.
2. "Gross" wells mean the number of wells in which Breitburn has an interest and includes unit wells.
3. "Net" wells means the aggregate number of wells obtained by multiplying each gross well by Breitburn's percentage interest.

Land Holdings

The following table sets out for the Breitburn Properties the total land holdings of proved and unproved properties to be acquired by the Trust. Breitburn has no properties without attributed reserves.

			Unproved
	Developed	(Acres)	Properties	(Acres)	Total	(Acres)
	Gross	Net(1)	Gross	Net	Gross	Net(1)
California
Alamitos	150	150	-	-	150	150
Beverly Hills East	315	309	-	-	315	309
Brea Olinda	300	300	-	-	300	300
East Coyote	612	31	-	-	612	31
Recreation Park	133	78	-	-	133	78
Rosecrans	312	312	-	-	312	312
Santa Fe Springs	580	580	-	-	580	580
Sawtelle	633	63	-	-	633	63
Total California	3,035	1,823	-	-	3,035	1,823
Wyoming
Lost Dome	300	94	-	-	300	94
	3,335	1,917	-	-	3,335	1,917

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		Unproved
Developed	(Acres)	Properties	(Acres)	Total	(Acres)
Gross	Net(1)	Gross	Net	Gross	Net(1)
3,335	1,917	-	-	3,335	1,917

Forward Contracts

Details of forward contracts associated with the Breitburn Properties are provided below. The impact of these contracts is included in the future net revenues presented in the tables of reserves and values.

Year	Type	Product	Terms	Volume	Contract Period
2004	Financial	Light Oil	US$ 25.07	250 bpd	Jan. 2004 Jun. 2004
	Financial	Light Oil	US$ 25.07	500 bpd	Jul. 2004 Dec. 2004
	Financial	Light Oil	US$ 24.48	250 bpd	Jan. 2004 Jun. 2004
	Financial	Light Oil	US$ 23.35	1,000 bpd	Jan. 2004 Jun. 2004
	Financial	Light Oil	US$ 25.20	500 bpd	Jan. 2004 Jun. 2004
	Financial	Light Oil	US$ 24.75	500 bpd	Jan. 2004 Jun. 2004
	Financial	Light Oil	US$ 24.75 (extended June 2004)	500 bpd	Jul. 2004 Dec. 2004
	Financial	Light Oil	US$ 23.09	250 bpd	Jan. 2004 Dec. 2004
	Financial	Light Oil	US$ 23.03	750 bpd	Jul. 2004 Dec. 2004
2005	Financial	Light Oil	US$ 23.96	2,000 bpd	Jan. 2005 Dec. 2005
	Financial	Light Oil	US$ 25.07 (extended Dec. 2004)	500 bpd	Jan. 2005 Jun. 2005
2006	Financial	Light Oil	US$ 23.70	500 bpd	Jan. 2006 Dec. 2006

Costs Incurred

A total of $17,891,000 and $4,345,628, respectively, in development costs were incurred in respect of the Breitburn Properties for the year ended December 31, 2003 and the three months ended March 31, 2004, using an exchange rate 0.715 $US/$Cdn for 2003 and 0.75 $US/$Cdn for the first quarter of 2004.

Exploration and Development Activities

The following table sets forth the gross and net exploratory and development wells drilled on the Breitburn Properties during the periods indicated.

	Three Months Ended	March 31, 2004	Year Ended	December 31, 2003
	Gross	Net	Gross	Net
Light and Medium Oil	1	1	3	2.4
Natural Gas	-	-	-	-
Service	-	-	1	0.9
Dry	-	-	-	-
Total	1	1	4	3.3

Production Estimates

The following table sets out the volume of production estimated for the period from January 1, 2004 to December 31, 2004 for the Breitburn Properties, which is reflected in the estimate of future net revenue disclosed in the tables contained under "Oil and Natural Gas Reserves" (Total Proved Forecast Prices and Costs).

- 16 -

	Light and			Natural Gas
	Medium Oil	Heavy Oil	Natural Gas	Liquids	Total
	(bbls/d)	(bbls/d)	(mcf/d)	(bbls/d)	(boe/d)
2004 (12 months)	4,126	-	2,549	156	4,707

Proved developed non-producing and proved undeveloped reserves from East Beverly Hills and Santa Fe Springs fields are scheduled to be brought on production throughout 2004, thereby increasing the 2004 projected volume from current and historic volumes.

Proved and Probable Developed Non-producing reserves have been assigned to the waterflood of the Bell zone at Santa Fe Springs. This is an expansion of existing waterflood operations in the Sante Fe Springs field. The Bell waterflood will be implemented in two phases with phase one commencing in 2004 and phase two commencing in 2005.

Proved and probable developed non-producing reserves have been assigned to shut-in or suspended wells in various onshore fields in Los Angeles County, California. Breitburn has an ongoing program to conduct recompletion or remedial work that is required to return these wells to production. Several wells have been returned to production in 2004 with more planned for the balance of 2004 and for the subsequent two years.

The undeveloped reserves and the timing for development of these reserves is discussed under "Undeveloped Reserves" in this short form prospectus.

Production History

The following tables summarize certain information in respect of production, product prices received, royalties paid, operating expenses and resulting netback in respect of the Breitburn Properties for the periods indicated. Current production from the Breitburn Properties is approximately 3,675 boe/d consisting of 2.1 mmcf/d of natural gas, 3,330 bbls/d of crude oil and NGLs.

	Quarter Ended
	2004	2003
	Mar. 31	Dec. 31	Sept. 30	June 30	Mar. 31
Average Daily Production
Light and Medium Crude Oil (bbls/d)	3,328	3,524	3,530	4,054	4,856
Gas (mcf/d)	1,238	1,502	1,513	1,119	1,572
NGL (bbls/d)	25	21	31	30	23
Combined (boe/d)	3,559	3,795	3,813	4,271	5,141
Average Price Received
Light and Medium Crude Oil ($/bbls)	$42.43	$38.88	$37.55	$35.29	$41.80
Gas ($/mcf)	$7.99	$6.55	$7.44	$7.99	$6.60
NGL ($bbls)	$40.32	$30.55	$31.72	$33.48	$38.77
Combined ($/boe)	$42.73	$38.85	$37.97	$35.82	$41.68

	Quarter Ended
	2004		2003
	Mar. 31	Dec. 31	Sept. 30	June 30	Mar. 31
Royalties
Light and Medium Crude Oil ($/bbl)	$3.87	$3.49	$3.53	$4.45	$4.14
Gas ($/mcf)	$0.87	$0.60	$0.47	$1.13	$0.70
NGL ($/bbls)	$8.61	$8.93	$7.32	$8.54	$8.20
Combined ($/boe)	$3.98	$3.53	$3.51	$4.58	$4.17
Operating Expenses
Combined ($/boe)	$13.45	$14.71	$13.13	$12.35	$12.15
Netback Received
Combined ($/boe)	$25.30	$20.61	$21.33	$18.89	$25.36

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Note:

1. Exchange rate 0.715 $US/$Cdn for 2003 and 0.75 $US/$Cdn for the first quarter of 2004. Assumes average royalty of 11%.

The following table indicates the average daily production from the important fields associated with the Breitburn Properties for the year ended December 31, 2003.

	Light/Medium
	Crude Oil	Natural Gas	NGL	Total
	(bbls/)	(mcf/d)	(bbls/d)	(boe/d)
California
Santa Fe Springs	1,726	-	-	1,726
Beverly Hills East	599	828	-	737

Significant Factors or Uncertainties

There are no significant factors or uncertainties that may impact the reserves and values attributable to the Breitburn Properties other than those general factors relating to the oil and gas business as set forth in the AIF under "Risk Factors" and as described in this short form prospectus.

Undeveloped Reserves

The following table sets forth the volumes of net proved undeveloped reserves that were attributed for each of Breitburn's product types for the most recent five financial years, based upon constant prices and costs. Breitburn's proved and probable undeveloped reserves as of December 31, 2003 are attributed in accordance with NI 51-101. Prior to this time, Breitburn's reserves were prepared according to the United States Securities and Exchange Commission regulations. As a result, no probable reserves were assigned for these prior time periods.

	Light and Medium	Heavy Oil	Natural Gas	Natural Gas Liquids
Proved Undeveloped	Oil (mbbl)	(mbbl)	(mmcf)	(mbbl)
Aggregate prior to 1999	8,584	-	4,424	-
1999	9,825	-	5,290	-
2000	9,789	-	23,170	-
2001	11,624	-	18,904	-
2002	12,932	-	22,873	394
2003	8,777	-	9,629	676

The most significant proved undeveloped reserves for the Breitburn Properties are represented by the East Beverly Hills Field. Undeveloped reserves at East Beverly Hills consist of infill development and injection wells, which are scheduled to be drilled over the next two years from a central urban drillsite with adjacent production facilities. East Beverly Hills Undeveloped reserves have been attributed to expansion of the existing pressure maintenance scheme (waterflood) as well as to the infill development wells.

Undeveloped reserves have also been assigned to expansion of the Stern zone waterflood pilot at the East Coyote field in Orange County, California. This waterflood is scheduled to be implemented in two phases with phase one commencing in 2004 and phase two commencing in 2006.

The basis for development of the undeveloped reserves over a two to four year time frame is to replace naturally occurring production declines rather than bring all the production on stream at one time.

EFFECT OF THE BREITBURN ACQUISITION ON THE TRUST

Selected Pro Forma Reserves and Operational Information

The following table sets forth certain reserves and operational information with respect to the Trust and Breitburn on a pro forma combined basis as at and for the periods indicated.

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	The Trust(1)	Breitburn (2)	Combined
Proved Reserves
Crude oil and NGLs (mbbl)	30,779	29,130	59,909
Natural gas (bcf)	187,505	17,372	204,877
Total (mboe)	62,030	32,026	94,055
Proved plus Probable Reserves
Crude oil and NGLs (mbbl)	41,879	35,865	77,743
Natural gas (bcf)	237,719	21,422	259,142
Total (mboe)	81,498	39,435	120,934
Net Present Value of Future Net Revenue from
Reserves Discounted at 10% ($ millions)
Proved Reserves	533	179	712
Proved plus Probable Reserves	642	229	871
Forecast Average Daily Production
(for the year 2004)(3)
Crude oil and NGLs (bbls/d)	18,326	4,282	22,608
Natural gas (mmcf/d)	89,150	2,549	91,699
Total (boe/d)	33,184	4,707	37,891
Undeveloped Land Holdings
(thousands of net acres)(4)	478	-	478
Oil and Natural Gas Wells (net wells)(5)
Producing oil wells	1,158.0	234.6	1392.6
Producing natural gas wells	648.1	-	648.1

Notes:

1. The Trust reserves includes Provident Energy Ltd. reserves as evaluated by McDaniel & Associates Consultants Ltd. based on forecast prices and costs as of December 31, 2003; Olympia reserves as evaluated by Gilbert Laustsen Jung Associates Ltd. effective January 1, 2004 using forecast prices and costs; and Viracocha reserves as evaluated by Gilbert Laustsen Jung Associates Ltd. effective January 1, 2004 using forecast prices and costs.
2. Breitburn reserves as evaluated by NSA as of December 31, 2003 and by CGA as of December 31, 2003 based on forecast prices and costs using McDaniel & Associates Consultants Ltd. January 1, 2004 price forecast.
3. Forecast Average Daily Production based on Total Proved reserves reports.
4. Net wells means the aggregate number of wells obtained by multiplying each gross well by the respective entity's percentage interest.

DETAILS OF THE OFFERING

The offering consists of 12,100,000 Trust Units at a price of $10.40 per Trust Unit and 50,000 Debentures at a price of $1,000 per Debenture. An additional 1,000,000 Trust Units may be issued if the Underwriters' Option is exercised in full. The following is a summary of the material attributes and characteristics of the Trust Units and the Debentures. This summary does not purport to be complete and is subject to, and qualified by, reference to the terms of the Trust Indenture with respect to the Trust Units, and reference to the terms of the Indenture (as defined below) with respect to the Debentures.

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 termination or winding-up of the Trust. All Trust Units shall 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

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holders of Trust Units for each Trust Unit held. A complete description of the redemption rights associated with the Trust Units is described under "Information Concerning Provident Energy Trust, Provident Energy Ltd. and Certain Subsidiaries" in the AIF. The Trust Indenture provides that 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 of the Trust or any other person pursuant to the Trust Indenture.

The Trust Indenture, among other things, provides for the calling of meetings of Unitholders, the conduct of business thereof, notice provisions, the appointment and removal of the trustee of the Trust and the form of Trust Unit certificates, and may be amended from time to time. Substantive amendments to the Trust Indenture, including early termination of the Trust and the sale or transfer of the property of the Trust as an entirety or substantially as an entirety, requires approval by a special meeting of Unitholders at which a resolution must be passed by a majority of not less than 66 2/3% of the votes cast, either in person or by proxy, at such meeting or approval in writing by holders of not less than 66 2/3% of the outstanding Trust Units.

Unitholders of record on or about the 21st day of each calendar month (or such other day as determined by the Trust) are entitled to receive cash distributions of the Trust in respect of that month. Such distributions are made on or about the 15th day of the following month.

Debentures

General

The Debentures will be issued under a debenture trust indenture (the "Indenture") to be dated as of the Closing Date which will be made among the Trust, Provident and Computershare Trust Company of Canada (the "Debenture Trustee"). The Debentures authorized for issue immediately will be unlimited.

The Debentures will be dated as of the Closing Date and will be issuable only in denominations of $1,000 and integral multiples thereof. The Maturity Date for the Debentures will be on July 31, 2009.

The Debentures will bear interest from the date of issue at 8% per annum, which will be payable semiannually in arrears on July 31 and January 31 in each year, commencing January 31, 2005. The first interest payment will include interest accrued from the closing of the offering to but excluding January 31, 2005.

The principal amount of the Debentures will be payable in lawful money of Canada or, at the option of the Trust and subject to applicable regulatory approval, by payment of Trust Units as further described under "Payment upon Redemption or Maturity" and "Redemption and Purchase". The interest on the Debentures will be payable in lawful money of Canada including, at the option of the Trust and subject to applicable regulatory approval, in accordance with the Unit Interest Payment Election as described under "Interest Payment Option".

The Debentures will be direct obligations of the Trust and will not be secured by any mortgage, pledge, hypothec or other charge and will be subordinated to other liabilities of the Trust as described under "Subordination". The Indenture will not restrict the Trust from incurring additional indebtedness for borrowed money or from mortgaging, pledging or charging its properties to secure any indebtedness.

Conversion Privilege

The Debentures will be convertible at the holder's option into fully paid and non-assessable Trust Units at any time prior to the close of business on the earlier of the Maturity Date and the business day immediately preceding the date specified by the Trust for redemption of the Debentures, at a conversion price of $12.00 per Trust Unit, being a conversion rate of 83.3333 Trust Units for each $1,000 principal amount of Debentures. Holders converting their Debentures will receive all accrued and unpaid interest thereon.

Subject to the provisions thereof, the Indenture will provide for the adjustment of the conversion price in certain events including: (a) the subdivision or consolidation of the outstanding Trust Units; (b) the distribution of Trust Units to holders of Trust Units by way of distribution or otherwise other than an issue of securities to holders of Trust Units who have elected to receive distributions in securities of the Trust in lieu of receiving cash distributions paid in the ordinary course; (c) the issuance of options, rights or warrants to holders of Trust Units

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entitling them to acquire Trust Units or other securities convertible into Trust Units at less than 95% of the then current market price (as defined below) of the Trust Units; and (d) the distribution to all holders of Trust Units of any securities or assets (other than cash distributions and equivalent distributions in securities paid in lieu of cash distributions in the ordinary course). There will be no adjustment of the conversion price in respect of any event described in (b), (c) or (d) above if the holders of the Debentures are allowed to participate as though they had converted their Debentures prior to the applicable record date or effective date. The Trust will not be required to make adjustments in the conversion price unless the cumulative effect of such adjustments would change the conversion price by at least 1%.

The term "current market price" will be defined in the Indenture to mean the weighted average trading price of the Trust Units on the TSX for the 20 consecutive trading days ending on the fifth trading day preceding the date of the applicable event.

In the case of any reclassification or capital reorganization (other than a change resulting from consolidation or subdivision) of the Trust Units or in the case of any consolidation, amalgamation or merger of the Trust with or into any other entity, or in the case of any sale or conveyance of the properties and assets of the Trust as, or substantially as, an entirety to any other entity, or a liquidation, dissolution or winding-up of the Trust, the terms of the conversion privilege shall be adjusted so that each holder of a Debenture shall, after such reclassification, capital reorganization, consolidation, amalgamation, merger, sale, conveyance, liquidation, dissolution or winding-up, be entitled to receive the number of Trust Units such holder would be entitled to receive if on the effective date thereof, it had been the holder of the number of Trust Units into which the Debenture was convertible prior to the effective date of such reclassification, capital reorganization, consolidation, amalgamation, merger, sale, conveyance, liquidation, dissolution or winding-up.

No fractional Trust Units will be issued on any conversion but in lieu thereof the Trust shall satisfy fractional interests by a cash payment equal to the current market price of any fractional interest.

Redemption and Purchase

The Debentures will not be redeemable on or before July 31, 2007. After July 31, 2007 and prior to maturity, the Debentures may be redeemed in whole or in part from time to time at the option of the Trust on not more than 60 days and not less than 30 days notice, at a Redemption Price of $1,050 per Debenture after July 31, 2007 until July 31, 2008 and at a Redemption Price of $1,025 per Debenture thereafter until maturity, in each case, plus accrued and unpaid interest thereon, if any.

In the case of redemption of less than all of the Debentures, the Debentures to be redeemed will be selected by the Debenture Trustee on a pro rata basis or in such other manner as the Debenture Trustee deems equitable.

The Trust will have the right to purchase Debentures in the market, by tender or by private contract.

Payment upon Redemption or Maturity

On redemption or at maturity, the Trust will repay the indebtedness represented by the Debentures by paying to the Debenture Trustee in lawful money of Canada an amount equal to the aggregate Redemption Price of the outstanding Debentures which are to be redeemed or the principal amount of the outstanding Debentures which have matured, together with accrued and unpaid interest thereon. The Trust may, at its option, on not more than 60 and not less than 40 days prior notice and subject to applicable regulatory approval, elect to satisfy its obligation to pay the applicable Redemption Price of the Debentures which are to be redeemed or the principal amount of the Debentures which have matured, as the case may be, by issuing freely tradeable Trust Units to the holders of the Debentures. Any accrued and unpaid interest thereon will be paid in cash. The number of Trust Units to be issued will be determined by dividing the aggregate Redemption Price of the outstanding Debentures which are to be redeemed or the principal amount of the outstanding Debentures which have matured, as the case may be, by 95% of the current market price on the date fixed for redemption or the maturity date, as the case may be. No fractional Trust Units will be issued on redemption or maturity but in lieu thereof the Trust shall satisfy fractional interests by a cash payment equal to the current market price of any fractional interest.

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Subordination

The payment of the principal of, and interest on, the Debentures will be subordinated in right of payment, as set forth in the Indenture, to the prior payment in full of all Senior Indebtedness and indebtedness to trade creditors of the Trust. "Senior Indebtedness" of the Trust will be defined in the Indenture as the principal of and premium, if any, and interest on and other amounts in respect of all indebtedness of the Trust (whether outstanding as at the date of Indenture or thereafter incurred), other than indebtedness evidenced by the Debentures and all other existing and future debentures (including the 8.75% Debentures and the 10.5% Debentures) or other instruments of the Trust which, by the terms of the instrument creating or evidencing the indebtedness, is expressed to be pari passu with, or subordinate in right of payment to, the Debentures. Subject to statutory or preferred exceptions or as may be specified by the terms of any particular securities, each debenture issued under the Indenture will rank pari passu with each other debenture, and with all other present and future subordinated and unsecured indebtedness of the Trust except for sinking provisions (if any) applicable to different series of debentures or similar types of obligations of the Trust.

The Indenture will provide that in the event of any insolvency or bankruptcy proceedings, or any receivership, liquidation, reorganization or other similar proceedings relative to the Trust, or to its property or assets, or in the event of any proceedings for voluntary liquidation, dissolution or other winding-up of the Trust, whether or not involving insolvency or bankruptcy, or any marshalling of the assets and liabilities of the Trust, then those holders of Senior Indebtedness, including any indebtedness to trade creditors, will receive payment in full before the holders of Debentures will be entitled to receive any payment or distribution of any kind or character, whether in cash, property or securities, which may be payable or deliverable in any such event in respect of any of the Debentures or any unpaid interest accrued thereon. The Indenture will also provide that the Trust will not make any payment, and the holders of the Debentures will not be entitled to demand, institute proceedings for the collection of, or receive any payment or benefit (including without any limitation by set-off, combination of accounts or realization of security or otherwise in any manner whatsoever) on account of indebtedness represented by the Debentures (a) in a manner inconsistent with the terms (as they exist on the date of issue) of the Debentures or (b) at any time when an event of default has occurred under the Senior Indebtedness and is continuing and the notice of such event of default has been given by or on behalf of the holders of Senior Indebtedness to the Trust, unless the Senior Indebtedness has been repaid in full.

The Debentures will also be effectively subordinate to claims of creditors of the Trust's subsidiaries except to the extent the Trust is a creditor of such subsidiaries ranking at least pari passu with such other creditors. Specifically, the Debentures will be effectively subordinated in right of payment to the prior payment in full of all indebtedness under the Credit Facility, as defined herein.

Priority over Trust Distributions

The Trust Indenture provides that certain expenses of the Trust must be deducted in calculating the amount to be distributed to the Unitholders. Accordingly, the funds required to satisfy the interest payable on the Debentures, as well as the amount payable upon redemption or maturity of the Debentures or upon an Event of Default (as defined below), will be deducted and withheld from the amounts that would otherwise be payable as distributions to Unitholders.

Change of Control of the Trust

Within 30 days following the occurrence of a change of control of the Trust involving the acquisition of voting control or direction over 66 2/3% or more of the Trust Units (a "Change of Control"), the Trust will be required to make an offer in writing to purchase all of the Debentures then outstanding (the "Offer"), at a price equal to 101% of the principal amount thereof plus accrued and unpaid interest (the "Offer Price").

The Indenture contains notification and repurchase provisions requiring the Trust to give written notice to the Debenture Trustee of the occurrence of a Change of Control within 30 days of such event together with the Offer. The Debenture Trustee will thereafter promptly mail to each holder of Debentures a notice of the Change of Control together with a copy of the Offer to repurchase all the outstanding Debentures.

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If 90% or more in aggregate principal amount of the Debentures outstanding on the date of the giving of notice of the Change of Control have been tendered to the Trust pursuant to the Offer, the Trust will have the right and obligation to redeem all the remaining Debentures at the Offer Price. Notice of such redemption must be given by the Trust to the Debenture Trustee within 10 days following the expiry of the Offer, and as soon as possible thereafter, by the Debenture Trustee to the holders of the Debentures not tendered pursuant to the Offer.

Interest Payment Option

The Trust may elect, from time to time, to satisfy its obligation to pay interest on the Debentures (the "Interest Obligation"), on the date it is payable under the Indenture (an "Interest Payment Date"), by delivering sufficient Trust Units to the Debenture Trustee to satisfy all or any part of the Interest Obligation in accordance with the Indenture (the "Unit Interest Payment Election"). The Indenture will provide that, upon such election, the Debenture Trustee shall (a) accept delivery from the Trust of Trust Units, (b) accept bids with respect to, and consummate sales of, such Trust Units, each as the Trust shall direct in its absolute discretion, (c) invest the proceeds of such sales in short-term permitted government securities (as defined in the Indenture) which mature prior to the applicable Interest Payment Date, and use the proceeds received from such permitted government securities, together with any proceeds from the sale of Trust Units not invested as aforesaid, to satisfy the Interest Obligation, and (d) perform any other action necessarily incidental thereto.

The Indenture will set forth the procedures to be followed by the Trust and the Debenture Trustee in order to effect the Unit Interest Payment Election. If a Unit Interest Payment Election is made, the sole right of a holder of Debentures in respect of interest will be to receive cash from the Debenture Trustee out of the proceeds of the sale of Trust Units (plus any amount received by the Debenture Trustee from the Trust attributable to any fractional Trust Units) in full satisfaction of the Interest Obligation, and the holder of such Debentures will have no further recourse to the Trust in respect of the Interest Obligation.

Neither the Trust's making of the Unit Interest Payment Election nor the consummation of sales of Trust Units will (a) result in the holders of the Debentures not being entitled to receive on the applicable Interest Payment Date cash in an aggregate amount equal to the interest payable on such Interest Payment Date, or (b) entitle such holders to receive any Trust Units in satisfaction of the Interest Obligation.

Events of Default

The Indenture will provide that an event of default ("Event of Default") in respect of the Debentures will occur if any one or more of the following described events has occurred and is continuing with respect of the Debentures: (a) failure for 10 days to pay interest on the Debentures when due; (b) failure to pay principal or premium, if any, when due on the Debentures, whether at maturity, upon redemption, by declaration or otherwise; (c) certain events of bankruptcy, insolvency or reorganization of the Trust under bankruptcy or insolvency laws; or (d) default in the observance or performance of any material covenant or condition of the Indenture and continuance of such default for a period of 30 days after notice in writing has been given by the Debenture Trustee to the Trust specifying such default and requiring the Trust to rectify the same. If an Event of Default has occurred and is continuing, the Debenture Trustee may, in its discretion, and shall upon request of holders of not less than 25% in principal amount of Debentures, declare the principal of and interest on all outstanding Debentures to be immediately due and payable. In certain cases, the holders of a majority of the principal amount of the Debentures then outstanding may, on behalf of the holders of all Debentures, waive any Event of Default and/or cancel any such declaration upon such terms and conditions as such holders shall prescribe.

Offers for Debentures

The Indenture will contain provisions to the effect that if an offer is made for the Debentures which is a take-over bid for Debentures within the meaning of the Securities Act (Alberta) and not less than 90% of the Debentures (other than Debentures held at the date of the take-over bid by or on behalf of the offeror or associates or affiliates of the offeror) are taken up and paid for by the offeror, the offeror will be entitled to acquire the Debentures held by the holders of Debentures who did not accept the offer on the terms offered by the offeror.

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Modification

The rights of the holders of the Debentures as well as any other series of debentures that may be issued under the Indenture may be modified in accordance with the terms of the Indenture. For that purpose, among others, the Indenture will contain certain provisions which will make binding on all debenture holders resolutions passed at meetings of the holders of debentures by votes cast thereat by holders of not less than 66 2/3% of the principal amount of the debentures present at the meeting or represented by proxy, or rendered by instruments in writing signed by the holders of not less than 66 2/3% of the principal amount of the debentures. In certain cases, the modification will, instead or in addition, require assent by the holders of the required percentage of debentures of each particularly affected series.

Limitation on Issuance of Additional Debentures

The Indenture will provide that the Trust shall not issue additional convertible debentures of equal ranking if the principal amount of all issued and outstanding convertible debentures of the Trust exceeds 25% of the Total Market Capitalization of the Trust immediately after the issuance of such additional convertible debentures. "Total Market Capitalization" will be defined in the Indenture as the total principal amount of all issued and outstanding debentures of the Trust which are convertible at the option of the holder into Trust Units of the Trust plus the amount obtained by multiplying the number of issued and outstanding Trust Units of the Trust by the current market price of the Trust Units on the relevant date.

Book-Entry System for Debentures

The Debentures will be issued in "book-entry only" form and must be purchased or transferred through a participant in the depository service of CDS (a "Participant"). On the Closing Date, the Debenture Trustee will cause the Debentures to be delivered to CDS and registered in the name of its nominee. The Debentures will be evidenced by a single book-entry only certificate. Registration of interests in and transfers of the Debentures will be made only through the depository service of CDS.

Except as described below, a purchaser acquiring a beneficial interest in the Debentures (a "Beneficial Owner") will not be entitled to a certificate or other instrument from the Debenture Trustee or CDS evidencing that purchaser's interest therein, and such purchaser will not be shown on the records maintained by CDS, except through a Participant. Such purchaser will receive a confirmation of purchase from the Underwriter or other registered dealer from whom Debentures are purchased.

Neither the Trust nor the Underwriters will assume any liability for: (a) any aspect of the records relating to the beneficial ownership of the Debentures held by CDS or the payments relating thereto; (b) maintaining, supervising or reviewing any records relating to the Debentures; or (c) any advice or representation made by or with respect to CDS and contained in this short form prospectus and relating to the rules governing CDS or any action to be taken by CDS or at the direction of its Participants. The rules governing CDS provide that it acts as the agent and depositary for the Participants. As a result, Participants must look solely to CDS and Beneficial Owners must look solely to Participants for the payment of the principal and interest on the Debentures paid by or on behalf of the Trust to CDS.

As indirect holders of Debentures, investors should be aware that they (subject to the situations described below): (a) may not have Debentures registered in their name; (b) may not have physical certificates representing their interest in the Debentures; (c) may not be able to sell the Debentures to institutions required by law to hold physical certificates for securities they own; and (d) may be unable to pledge Debentures as security.

The Debentures will be issued to Beneficial Owners in fully registered and certificate form (the "Debenture Certificates") only if: (a) required to do so by applicable law; (b) the book-entry only system ceases to exist; (c) the Trust or CDS advises the Debenture Trustee that CDS is no longer willing or able to properly discharge its responsibilities as depositary with respect to the Debentures and the Trust is unable to locate a qualified successor; (d) the Trust, at its option, decides to terminate the book-entry only system through CDS; or (e) after the occurrence of an Event of Default (as defined herein), Participants acting on behalf of Beneficial Owners representing, in the aggregate, more than 25% of the aggregate principal amount of the Debentures then outstanding advise CDS in

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writing that the continuation of a book-entry only system through CDS is no longer in their best interest provided the Debenture Trustee has not waived the Event of Default in accordance with the terms of the Indenture.

Upon the occurrence of any of the events described in the immediately preceding paragraph, the Debenture Trustee must notify CDS, for and on behalf of Participants and Beneficial Owners, of the availability through CDS of Debenture Certificates. Upon surrender by CDS of the single certificate representing the Debentures and receipt of instructions from CDS for the new registrations, the Debenture Trustee will deliver the Debentures in the form of Debenture Certificates and thereafter the Trust will recognize the holders of such Debenture Certificates as debentureholders under the Indenture.

Interest on the Debentures will be paid directly to CDS while the book-entry only system is in effect. If Debenture Certificates are issued, interest will be paid by cheque drawn on the Trust and sent by prepaid mail to the registered holder or by such other means as may become customary for the payment of interest. Payment of principal, including payment in the form of Trust Units if applicable, and the interest due, at maturity or on a redemption date, will be paid directly to CDS while the book-entry only system is in effect. If Debenture Certificates are issued, payment of principal, including payment in the form of Trust Units if applicable, and interest due, at maturity or on a redemption date, will be paid upon surrender thereof at any office of the Debenture Trustee or as otherwise specified in the Indenture.

INTEREST COVERAGE

The following interest coverages are calculated on a consolidated basis for the twelve-month periods ended December 31, 2003 and March 31, 2004 and are derived from audited financial information, in the case of the period ended December 31, 2003, and unaudited financial information, in the case of the period ended March 31, 2004. Pursuant to current Canadian generally accepted accounting principles, the Debentures will be included in Unitholders' Equity and the interest paid on the Debentures will be charged to accumulated loss as distributions to Unitholders, which is consistent with the accounting treatment applied in respect of the 8.75% Debentures and the 10.5% Debentures.

The loss of the Trust before interest and income tax recovery for the year ended December 31, 2003 was $10.0 million. The loss of the Trust before interest and income tax recovery for the twelve-month period ended March 31, 2004 was $15.7 million, The interest expense for the year ended December 31, 2003 and the twelve-month period ended March 31, 2004 was $9.7 million and $9.6 million, respectively, for a coverage ratio of less than one in each case. The dollar amount of the coverage deficiency for the year ended December 31, 2003 and the twelve-month period ended March 31, 2004 would have been $19.7 million and $25.3 million, respectively. Cash flow (defined as funds from operations before working capital changes) before interest for the 12 months ended December 31, 2003 and March 31, 2004 respectively were $145.4 million and $142.6 million, resulting in cash flow coverage for the period of 14.9 and 14.8 times, respectively.

After giving effect to the issuance of the Debentures, the pro forma earnings and cash flow of the Trust before interest and income tax recovery remains unchanged. After giving effect to the equity treatment of the Debentures, the pro forma interest expense for the year ended December 31, 2003 and the twelve-month period ended March 31, 2004 was unchanged.

After giving effect to the Breitburn Acquisition, the issuance of the Debentures and the acquisitions of Olympia and Viracocha, the pro forma earnings of the Trust before interest and income tax recovery for the year ended December 31, 2003 and the twelve-month period ended March 31, 2004 were $21.5 million and $29.6 million, respectively. After giving effect to the equity treatment of the Debentures, the pro forma interest expense for the year ended December 31, 2003 and the twelve-month period ended March 31, 2004 was $14.0 million and $13.8 million, respectively. As a result, the coverage ratio would be 1.5 times for the year ended December 31, 2003 and 2.1 times for the twelve month period ended March 31, 2004. Cash flow (defined as funds from operations before changes in working capital) before interest for the 12 month period ended December 31, 2003 and the twelve month period ended March 31, 2004 was $265.0 million and $278.3 million respectively, for a cash flow coverage ratio of 18.9 and 20.2 respectively.

If the Debentures offered hereunder and the Trust's previously issued 10.5% Debentures and 8.75% Debentures were both included in long-term debt and their respective carrying charges were included in interest

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expense, the pro forma interest coverage after giving effect to the Breitburn Acquisition and the acquisitions of Olympia and Viracocha, would be less than one for the year ended December 31, 2003 and for the twelve-month period ended March 31, 2004. The dollar amount of the coverage deficiency for the year ended December 31, 2003 and the twelve month period ended and March 31, 2004 would have been $8.7 million and $0.2 million, respectively. Pro forma cash flow coverage (defined as funds from operations before changes in working capital) before interest for the twelve month period ended December 31, 2003 and the twelve month period ended March 31, 2004 was 8.8 and 9.4, respectively.

PLAN OF DISTRIBUTION

Pursuant to an underwriting agreement dated as of June 15, 2004 (the "Underwriting Agreement") among the Trust, Provident and the Underwriters, the Trust has agreed to issue and sell an aggregate of 12,100,000 Trust Units and 50,000 Debentures to the Underwriters, and the Underwriters have severally agreed to purchase such Trust Units and Debentures on July 6, 2004 or on such other date as may be agreed among the parties to the Underwriting Agreement. Delivery of the Trust Units and Debentures is conditional upon payment on closing of $10.40 per Trust Unit and $1,000 per Debenture by the Underwriters to the Trust. The Underwriting Agreement provides that the Trust will pay the Underwriters' fee of $0.52 per Trust Unit and $40 per Debenture issued and sold by the Trust and for an aggregate fee payable by the Trust of $8,292,000, in consideration for the Underwriters' services in connection with the offering. The obligations of the Underwriters under the Underwriting Agreement are several and may be terminated upon the occurrence of certain events. The Underwriters are, however, obligated to take up and pay for all of the securities if any of the securities are purchased under the Underwriting Agreement.

The Trust has granted to the Underwriters the Underwriters' Option to purchase up to an additional 1,000,000 Trust Units on the same terms as the offering exercisable, in whole or in part, at any time until 48 hours prior to the closing of the offering, which additional Trust Units are qualified for distribution under this short form prospectus. If the Underwriters' Option is exercised in full, the total offering, the Underwriters' fee and the net proceeds to the Trust in respect of the offering of Trust Units will be $136,240,000, $6,812,000 and $129,428,000, respectively (prior to deducting expenses of the offering).

The offering price for the Trust Units and Debentures offered hereunder was determined by negotiation between the Trust and BMO Nesbitt Burns Inc., National Bank Financial Inc. and TD Securities Inc., on their own behalf and on behalf of the other Underwriters.

Pursuant to applicable securities legislation, the Underwriters may not, throughout the period of distribution under this short form prospectus, bid for or purchase Trust Units and Debentures. The foregoing restriction is subject to exceptions, provided the bid or purchase is not engaged in for the purpose of creating actual or apparent trading in, or raising the price of, the Trust Units and Debentures. These exceptions include a bid or purchase permitted under the bylaws and rules of the TSX relating to market stabilization and passive market-making activities. In connection with the offering, and subject to the foregoing, the Underwriters may effect transactions which stabilize or maintain the market price of the Trust Units and Debentures at levels above those which might otherwise prevail in the open market. Such transactions, if commenced, may be discontinued at any time.

Subscriptions will be received subject to rejection or allotment in whole or in part and the right is reserved to close the subscription books at any time without prior notice. Certificates for the Trust Units will be available for delivery at the closing of the offering, which is expected to occur on or about July 6, 2004. The Debentures will be issued in "book-entry only" form and must be purchased or transferred through a participant in the depository service of CDS. See "Details of the Offering-Book-Entry System for Debentures".

The TSX has approved the listing of the Trust Units and the Debentures distributed under this short form prospectus and the Trust Units issuable on conversion of the Debentures. Listing of the Trust Units and Debentures distributed under this short form prospectus and the Trust Units issuable on conversion of the Debentures on the TSX will be subject to the Trust fulfilling all of the listing requirements of the TSX on or before September 15, 2004. The Trust has also applied to list the Trust Units distributed under this short form prospectus and the Trust Units issuable on conversion, redemption or at maturity of the Debentures on the AMEX . Listing will be subject to the Trust fulfilling all of the listing requirements of the AMEX.

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There is currently no market through which the Debentures may be sold and purchasers may not be able to resell the Debentures purchased under this short form prospectus.

Neither the Trust Units nor the Debentures issued or made subject to issuance under the offering has been and will not be registered under the United States Securities Act of 1933, as amended (the "1933 Act") or any state securities laws, and accordingly may not be offered or sold within the United States except in transactions exempt from the registration requirements of the 1933 Act and applicable state securities laws. In addition, until 40 days after the commencement of the distribution of securities hereunder, any offer or sale of such securities within the United States by any dealer (whether or not participating in the distribution under the offering) may violate the registration requirements of the 1933 Act if such offer or sale is made otherwise than in accordance with Rule 144A or another exemption under the 1933 Act.

The Trust has agreed with the Underwriters that it will not, for the period ending 90 days after the closing of the offering, sell or offer to sell any Trust Units or any securities convertible into or exchangeable for Trust Units, without the prior consent of BMO Nesbitt Burns Inc., National Bank Financial Inc. and TD Securities Inc. on behalf of the Underwriters, pursuant to the Underwriting Agreement, such consent not to be unreasonably withheld, other than the issuance of Trust Units pursuant to the trust unit option plan of the Trust, the issuance of Trust Units pursuant to the premium distribution, distribution re-investment and optional trust unit purchase plan of the Trust, the issuance of Trust Units on exchange of the outstanding exchangeable shares of Provident and PAI, the issuance of Trust Units upon conversion or redemption of the 8.75% Debentures and the 10.5% Debentures and the issuance of Trust Units, if elected by the Trust, as payment of interest in respect of the 8.75% Debentures and the 10.5% Debentures.

RISK FACTORS

An investment in the Trust Units and Debentures is subject to certain risks. Prospective investors in the Trust Units and Debentures should carefully consider the risks described under "Risk Factors" in the AIF and the additional risk factors set forth below.

Possible Failure to Realize Anticipated Benefits of the Transaction

The Trust has agreed to acquire the Breitburn Properties through the Breitburn Acquisition to strengthen its position in the oil and natural gas industry and to create the opportunity to realize certain benefits. Achieving the benefits of the Breitburn Acquisition will depend in part on successfully consolidating functions and integrating operations, procedures and personnel in a timely and efficient manner, as well as the Trust's ability to realize the anticipated growth opportunities and synergies from integrating the Breitburn Properties into the Trust's existing business. The integration of the Breitburn Properties into the Trust's business will require the dedication of management effort, time and resources which may divert management's focus and resources from other strategic opportunities and from operational matters during this process. The integration process may result in the loss of key employees and the disruption of ongoing business, customer and employee relationships that may adversely affect the Trust's ability to achieve the anticipated benefits of the Breitburn Acquisition.

Operational Matters and Hazards Relating to the Breitburn Acquisition

The risk factors set forth in the Trust's AIF relating to the oil and natural gas business and the operations and reserves of the Trust apply equally in respect of the Breitburn Properties. The Trust has conducted due diligence on the Breitburn Properties in relation to environmental matters and has given Breitburn indemnities relating to environmental liabilities. There can be no assurance that the Trust has identified all of the environmental liabilities for which it has indemnified Breitburn. In particular, the reserve and recovery information contained in the reports of NSA and CGA in respect of the Breitburn Properties is only an estimate and the actual production from and ultimate reserves of those properties may be greater or less than the estimates contained in such report.

Market for Debentures

There is currently no market through which the Debentures may be sold and purchasers may not be able to resell the Debentures purchased under this short form prospectus. There can be no assurance that an active trading

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market will develop for the Debentures after the offering, or if developed, that such a market will be sustained at the price level of the offering.

Prior Ranking Indebtedness

The Debentures will be subordinate to all Senior Indebtedness and to any indebtedness of trade creditors of the Trust. The Debentures will also be effectively subordinate to claims of creditors of the Trust's subsidiaries except to the extent the Trust is a creditor of such subsidiaries ranking at least pari passu with such other creditors.

Absence of Covenant Protection

Other than the restriction on issuing additional convertible debentures, the Indenture will not restrict the Trust from incurring additional indebtedness for borrowed money or from mortgaging, pledging or charging its properties to secure any indebtedness. The Indenture will not contain any provision specifically intended to protect holders of the Debentures in the event of a future leveraged transaction involving the Trust.

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.

CAPITALIZATION OF THE TRUST

The following table sets forth the consolidated capitalization of the Trust as at December 31, 2003, and as at March 31, 2004, both before and after giving effect to the offering, the Breitburn Acquisition and the acquisitions of Olympia and Viracocha:

			As at March 31, 2004	As at March 31, 2004
			before giving effect to	after giving effect to the
			the offering, the	offering, the Breitburn
			Breitburn Acquisition	Acquisition and the
		As at	and the acquisitions of	acquisitions of Olympia
		December 31, 2003(8)	Olympia and Viracocha	and Viracocha
Designation	Authorized		(unaudited)	(unaudited)(4)
		(in thousands of dollars except per unit amounts)
Long Term Debt (1)	-	$236,500	$178,800	$268,360
Trust Units (2)	Unlimited	$803,229(3)	$858,644	$1,268,413
		(82,824,688 Trust Units)	(88,117,088 Trust Units)	(126,361.053 Trust
				Units)
Exchangeable Shares	-	$19,518	$17,441	$46,909
		(2,186,824 Trust Units)(5)	(2,013,874 Trust Units)(5)	(4,663,874 Trust Units)(5)
8% Debentures		-	-	$48,000
10.5% Debentures(6)	-	$47,600	$47,576	$47,576
8.75% Debentures(7)	-	$71,800	$71,800	$71,800

Notes:

1. As at March 31, 2004, Provident had a revolving term credit facility (the "Credit Facility") to a maximum of $310 million which bears interest in accordance with a pricing grid based on Provident's debt to cash flow multiple calculated using the most recent quarterly cash flow on an annualized basis. Based on Provident's cash flow for the quarter ended March 31, 2004, the interest rate pursuant to

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the pricing grid is equal to the prime rate plus 0.50 percent. The Credit Facility is secured by a first fixed and floating charge debenture in the minimum face amount of $500 million, a general assignment of book debts, a negative pledge and, if determined necessary by the lenders, an undertaking to provide first charges over major petroleum and natural gas reserves of Provident. As at March 31, 2004, the Trust had drawn $178.8 million against the Credit Facility and had $15.1 million of the Credit Facility drawn on letters of credit. At June 15, 2004 the facility had been amended to a maximum of $370 million.

2. As at March 31, 2004, the Trust had issued options to purchase 4,086,459 Trust Units to employees, directors and officers of Provident.

3. As at March 31, 2004, the Trust's Unitholders' equity consisted of $858.6 million of net capital contributions less $6.3 million of accumulated loss and $279.1 million of accumulated cash distributions on the Trust Units, $17.4 million of exchangeable shares, $15.2 million of accumulated interest on the 10.5% Debentures and 8.75% Debentures and an aggregate of $119.4 million of 10.5% Debentures and 8.75% Debentures.

4. Based on the issue of 13,385,579 Trust Units for proceeds of $148,848,000 for Olympia, 12,758,386 Trust Units for proceeds of $141,873,000 for Viracocha and 12,100,000 Trust Units by the Trust pursuant to the offering for an aggregate of $125,840,000 less the Underwriters' fee of $6.3 million and expenses of the issue estimated to be $0.5 million (without giving effect to the exercise of the Underwriters' Option).

5. Represents Trust Units issuable as of December 31, 2003 or March 31, 2004, as applicable, on the exchange of exchangeable shares.

6. The 10.5% Debentures bear interest at a rate of 10.5% per year payable semi-annually in arrears. The 10.5% Debentures mature on May 15, 2007 and are convertible into Trust Units at the option of the holder at a conversion price of $10.70 per Trust Unit at any time prior to the earlier of the maturity date or the date on which the 10.5% Debentures are redeemed by the Trust. The 10.5% Debentures are not redeemable by the Trust on or before May 15, 2005. The outstanding principal amount of the 10.5% Debentures are included in the Trust's consolidated balance sheet (net of costs to issue) as Unitholders' equity since the Trust has the option to settle both principal and interest obligations in Trust Units.

7. The 8.75% Debentures bear interest at a rate of 8.75% per year payable semi-annually in arrears. The 8.75% Debentures mature on December 31, 2008 and are convertible into Trust Units at the option of the holder at a conversion price of $11.05 per Trust Unit at any time prior to the earlier of the maturity date or the date on which the 8.75% Debentures are redeemed by the Trust. The 8.75% Debentures are not redeemable by the Trust on or before January 1, 2007. The outstanding principal amount of the 8.75% Debentures are included in the Trust's consolidated balance sheet (net of costs to issue) as Unitholders' equity since the Trust has the option to settle both principal and interest obligations in Trust Units.

8. The balances as at December 31, 2003 have been taken from the audited financial statements of the Trust as at December 31, 2003.  Individual balances presented have not been audited.

PRICE RANGE AND TRADING VOLUME OF THE TRUST UNITS

The outstanding Trust Units are traded on the TSX under the trading symbol "PVE.UN" and the AMEX under the trading symbol "PVX". The following table sets forth the closing price range and trading volume of the Trust Units as reported by the TSX and the AMEX for the periods indicated.

Toronto Stock Exchange

Period	High	Low	Volume (000's)
2003
First Quarter	$11.95	$ 9.85	19,001
Second Quarter	$12.75	$10.00	25,075
Third Quarter	$11.83	$10.45	24,068
Fourth Quarter	$11.75	$10.28	22,012
2004
January	$11.55	$10.70	4,008
February	$11.10	$9.21	4,625
March	$10.97	$9.75	4,523
April	$11.80	$10.65	8,581
May	$11.80	$10.98	3,775
June 1-25	$11.20	$10.33	11,984

On June25,2004, the closing price per Trust Unit on the TSX was $10.43.

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American Stock Exchange

Period	High	Low	Volume (000's)
2003
First Quarter	U.S. $8.24	U.S. $6.60	22,625
Second Quarter	U.S. $9.47	U.S. $6.75	45,502
Third Quarter	U.S. $8.53	U.S. $7.70	30,524
Fourth Quarter	U.S. $8.89	U.S. $7.81	40,261
2004
January	U.S. $9.06	U.S. $8.00	12,349
February	U.S. $8.37	U.S. $6.63	13,129
March	U.S. $8.25	U.S. $7.30	10,693
April	U.S. $9.00	U.S. $8.20	21,954
May	U.S. $8.60	U.S. $7.99	8,980
June 1-25	U.S. $8.23	U.S. $7.40	15,866

On June 25, 2004, the closing price per Trust Unit on the AMEX was U.S. $7.63.

RECORD OF CASH DISTRIBUTIONS

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

2001
March December	$2.54
2002

January December	$2.03
2003
January - December	$2.06
2004
January	$0.12

February	$0.12
March	$0.12
April	$0.12
May	$0.12

The Trust has declared a distribution of $0.12 per Trust Unit to be payable on July 15, 2004 to Unitholders of record on June 18, 2004. Purchasers of Trust Units pursuant to the offering will not be eligible to receive the distribution payable on July 15, 2004. However, it is anticipated that the offering will close prior to July 20, 2004, which is the record date for the distribution by the Trust to Unitholders payable on August 13, 2004. Accordingly, provided the offering closes prior to July 20, 2004, subscribers who complete their purchase from the Underwriters and continue to be the registered holder of such Trust Units on July 20, 2004 will be eligible to participate in the distribution of the Trust payable on August 13, 2004.

USE OF PROCEEDS

The net proceeds to the Trust from the sale of the Trust Units and Debentures are estimated to be approximately $167,048,000 after deducting the fees of $8,292,000 payable to the Underwriters and the estimated expenses of the offering of $500,000. If the Underwriters' Option is exercised in full the net proceeds from the offering are estimated to be approximately $176,928,000 after deducting the fees of $8,812,000 payable to the Underwriters and the estimated expenses of the offering of $500,000. See "Plan of Distribution". The net proceeds of the offering will be used by the Trust to repay indebtedness of Provident under its credit facilities incurred to fund the purchase price of the Breitburn Acquisition, to fund the Trust's capital expenditure program and for general corporate purposes. See "Relationship Among the Trust, Provident and Certain Underwriters".

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RELATIONSHIP AMONG THE TRUST, PROVIDENT AND CERTAIN UNDERWRITERS

Each of BMO Nesbitt Burns Inc., National Bank Financial Inc., TD Securities Inc. and Scotia Capital Inc. is an indirect wholly-owned subsidiary of one of the lenders (the "Lenders") to the Trust and Provident pursuant to the existing credit facilities of the Trust and Provident. In addition, the net proceeds of the offering will be used by the Trust to repay indebtedness incurred under a bridge facility (the "Bridge Facility") to one of the Lenders in the amount of U.S.$117 million incurred to fund the Breitburn Acquisition. Accordingly, the Trust may be considered a connected issuer of each of BMO Nesbitt Burns Inc., National Bank Financial Inc., TD Securities Inc. and Scotia Capital Inc. under applicable securities laws.

As at March 31, 2004, $178.8 million was outstanding under the Credit Facility. In addition, as of December 2, 2003, Provident had issued letters of credit to certain parties in the amount of $12.5 million to guarantee performance of its obligations under certain agreements. These letters of credit reduce the amount that Provident is able to borrow under the Credit Facility. Each of the Trust and Provident are in compliance with all material terms of the agreement governing the Credit Facility and the Bridge Facility, and none of the Lenders have waived any material breach by the Trust or Provident of such agreements since their execution. Neither the financial position of the Trust and Provident nor the value of the security under the Credit Facility or the Bridge Facility has changed substantially since the indebtedness under the facilities was incurred.

The decision to distribute the Trust Units and Debentures offered hereby and the determination of the terms of the distribution were made through negotiations primarily between Provident, on behalf of the Trust and BMO Nesbitt Burns Inc. on its own behalf and on behalf of the remaining Underwriters. The Lenders did not have any involvement in such decision or determination, but have been advised of the issuance and the terms thereof. As a consequence of the offering, BMO Nesbitt Burns Inc., National Bank Financial Inc., TD Securities Inc. and Scotia Capital Inc. will each receive its share of the Underwriters' fee.

CANADIAN FEDERAL INCOME TAX CONSIDERATIONS

In the opinion of Macleod Dixon LLP and Stikeman Elliott LLP, the following summary describes the principal Canadian federal income tax considerations pursuant to the Tax Act and the regulations thereunder (the "Regulations") generally applicable to a holder who acquires Debentures or Trust Units (collectively, the "Securities") pursuant to this offering and who, for purposes of the Tax Act and all relevant times, is resident or deemed to be resident in Canada, holds the Securities as capital property and deals at arm's length with the Trust. Generally, the Securities will be considered to be capital property to a holder provided the holder does not hold the Securities in the course of carrying on a business of trading or dealing in securities and has not acquired them in one or more transactions considered to be an adventure in the nature of trade. Certain holders who might not otherwise be considered to hold their Securities as capital property may, in certain circumstances, be entitled to have them treated as capital property by making the election permitted by subsection 39(4) of the Tax Act. This summary is not applicable to (a) a subscriber that is a "financial institution", as defined in the Tax Act for the purposes of the mark-to-market rules, or (b) a subscriber an interest in which would be a "tax shelter investment" as defined in the Tax Act. Any such subscriber should consult its own tax advisor with respect to an investment in the Securities.

This summary is based upon the provisions of the Tax Act and the Regulations in force as of the date hereof, all specific proposals to amend the Tax Act that have been publicly announced prior to the date hereof (the "Proposed Amendments") and counsels' understanding of the current published administrative practices of the Canada Customs and Revenue Agency. This summary assumes the Proposed Amendments will be enacted in the form proposed, however, no assurance can be given that the Proposed Amendments will be enacted in the form proposed, if at all. This summary is not exhaustive of all possible Canadian federal income tax considerations and, except for the Proposed Amendments, does not take into account any changes in the law, whether by legislative, governmental or judicial action, nor does it take into account provincial, territorial or foreign tax considerations, which may differ significantly from those discussed herein.

This summary is of a general nature only and is not intended to be, nor should it be construed to be, legal or tax advice to any particular holder of Securities, and no representations with respect to the income tax consequences to any holder are made. Consequently, holders of Securities should consult their own tax advisors for advice with respect to the tax consequences to them of acquiring Securities pursuant to this offering, having regard to their particular circumstances.

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Status of the Trust

Based on representations of Provident, the Trust currently qualifies, and will qualify on the date of the closing of this offering, as a "mutual fund trust" as defined in the Tax Act. This summary assumes that the Trust will continue to so qualify thereafter for the duration of its existence.

The qualification of the Trust as a mutual fund trust under the Tax Act requires that certain factual conditions generally be met throughout its existence. In order for the Trust to qualify as a mutual fund trust, either (i) it must not have been established or at any time be maintained primarily for the benefit of non-residents or (ii) subject to the Proposed Amendments discussed in the following paragraph, throughout the Trust's existence all or substantially all of its property must consist of property other than property that would be certain types of taxable Canadian property (as defined in the Tax Act). The Trust must also satisfy certain requirements with respect to the distribution of its Units and restrictions on its activities. The Trust has certain restrictions on its activities and its powers and certain rights against non-resident Unitholders such that it is reasonable to expect that these requirements will continue to be satisfied.

Under the Proposed Amendments, the Trust should have until January 1, 2007 to reduce the level of nonresident ownership of Trust Units to less than 50%, otherwise it will lose its status as a mutual fund trust for the purposes of the Tax Act effective on that date. The Trust has advised Counsel that it intends to actively take steps prior to January 1, 2007 to ensure that at and after that date fewer than 50% of the outstanding Trust Units will be owned by or for the benefit of non-residents. See "Risk Factors - General Risk Factors - Risks Associated With the Level of Foreign Ownership" in the AIF.

Should the Trust not qualify as a mutual fund trust, the income tax considerations would in some respects be materially different than those described below. See "Risk Factors General Risk Factors Risks Associated With the Level of Foreign Ownership" in the AIF.

Taxation of the Trust

The Trust is subject to taxation in each taxation year on its income for the year, including net realized taxable capital gains, less the portion thereof that is paid or payable in the year to Unitholders and which is deducted by the Trust in computing its income for the purposes of the Tax Act. An amount will be considered to be payable to a Unitholder in a taxation year only if it is paid in the year by the Trust or the Unitholder is entitled in that year to enforce payment of the amount. The taxation year of the Trust is the calendar year.

The Trust is required to include in its income for each taxation year all amounts (i) in respect of royalties held by it from Provident and Holdings Trust, including any amounts subject to set-off in respect of any Crown charges reimbursed to Provident or Holdings Trust, (ii) in respect of interest, (iii) in respect of dividends, and (iv) in respect of that portion of Holdings Trust's income for tax purposes for Holdings Trust's taxation year that ends in the Trust's taxation year that becomes payable in Holdings Trust's year to the Trust, together with all amounts designated to the Trust as reimbursed Crown charges in excess of the resource allowance deducted in computing Holdings Trust's income. Provided that appropriate designations are made by the Trust, certain dividends which would otherwise be included in its income as dividends received on shares owned by the Trust, including the shares of Provident, will be deemed to have been received by Unitholders and not to have been received by the Trust.

The Trust will be entitled to deduct, on an annual basis, reasonable administrative expenses incurred in its ongoing operations. The Trust will be entitled to deduct, over five years on a straight-line basis, prorated for short taxation years, any costs incurred by it in connection with the issuance of Trust Units or indebtedness (including the Debentures). The Trust may also deduct, in computing its income from all sources for a taxation year, an amount not exceeding 10 percent, on a declining balance basis, of its cumulative Canadian oil and gas property expense ("COGPE") account at the end of that year, prorated for short taxation years.

In accordance with the Regulations, the Trust may deduct in computing its income for a year a resource allowance generally calculated by reference to its "adjusted resource profits" as defined for purposes of the Tax Act. Crown royalties will become deductible and the deduction for resource allowance will be eliminated on a phase-in basis over a 5-year period starting in 2003. The excess, if any, of reimbursed Crown charges over the resource allowance deductible by the Trust in the year is deemed to be an amount that has become payable to the Unitholders,

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to the extent designated by the Trust. Counsel understands that the Trust will designate the full amount of any such excess annually in respect of the Unitholders. The Trust may claim as a deduction an amount that is less than the amount of its income that is paid or payable to Unitholders in a year if it designates such amount not to have been paid or become payable to the Unitholders. This may occur for example to utilize losses from prior taxation years.

Under the Trust Indenture, an amount equal to all of the income, including royalty, interest and dividend income of the Trust for each year, together with the taxable and non-taxable portions of any capital gains realized by the Trust in the year (net of the Trust's expenses and amounts, if any, required to be retained to pay any tax liability of the Trust) will be payable to the Unitholders. Subject to the exceptions described below, all amounts payable to the Unitholders shall be paid by way of cash distributions.

Under the Trust Indenture, income received by the Trust may be used to finance cash redemptions of Trust Units. Accordingly, such income so utilized will not be payable to holders of the Trust Units by way of cash distributions. In such circumstances, such income will be payable to holders of Trust Units in the form of additional Trust Units ("Reinvested Trust Units"). Moreover, under the Trust Indenture, the Trust may, in certain circumstances, issue its own notes or distribute property of the Trust to finance the redemption of Trust Units.

Where the Trust distributes property of the Trust to a Unitholder on a redemption of Trust Units, the Trust will be deemed to receive proceeds of disposition equal to the fair market value of such property at that time (the "Deemed Proceeds"), and such Deemed Proceeds may give rise to a capital gain or income to the Trust. The Trust will be entitled for each taxation year to reduce (or receive a refund in respect of) its liability, if any, for tax on its net taxable capital gains by an amount determined under the Tax Act based on the redemption or retraction of Trust Units during the year (the "Capital Gains Refund"). The Capital Gains Refund in a particular year may not completely offset the Trust's tax liability for such taxation year that may arise upon distributions of property in connection with the redemption of Trust Units. The Trust Indenture accordingly provides that income of the Trust which is required to satisfy any tax liability on the part of the Trust shall not be payable to Unitholders.

For purposes of the Tax Act, Counsel is advised that the Trust intends to deduct, in computing its income, the full amount available for deduction in each year to the extent of its income for the year otherwise determined. As a result of such deduction from income, it is expected that the Trust will not be liable for any material amount of tax under the Tax Act.

Taxation of Unitholders

A Unitholder will generally be required to include in computing income for a particular taxation year of the Unitholder the portion of the net income of the Trust for a taxation year, including taxable dividends and net realized taxable capital gains, that is paid or payable to the Unitholder in that particular taxation year, notwithstanding that any such amount is payable in Reinvested Trust Units. Income of a Unitholder from the Trust Units will be considered to be income from property and not resource income (or "resource profits") for the purposes of the Tax Act. Any loss of the Trust for the purposes of the Tax Act cannot be allocated to and treated as a loss of a Unitholder.

Provided that appropriate designations are made by the Trust, such portions of its net taxable capital gains and taxable dividends as are paid or payable to a Unitholder will effectively retain their character as taxable capital gains and taxable dividends, respectively, and shall be treated as such in the hands of the Unitholder for purposes of the Tax Act.

The non-taxable portion of net realized capital gains of the Trust that is paid or payable to a Unitholder in a year will not be included in computing the Unitholder's income for the year. Any other amount in excess of the net income of the Trust that is paid or payable by the Trust to a Unitholder in a year will not generally be included in the Unitholder's income for the year. However, where such an amount becomes payable to a Unitholder, other than as proceeds of disposition of Trust Units or fractions thereof, the adjusted cost base of the Trust Units held by such Unitholder will generally be reduced by such amount. To the extent that the adjusted cost base to a Unitholder of a Trust Unit is less than zero at any time in a taxation year, such negative amount will be deemed to be a capital gain of the Unitholder from the disposition of the Trust Unit in that year.

- 33 -

The cost to a Unitholder of Trust Units acquired pursuant to this offering will equal the purchase price of the Trust Units plus the amount of any other reasonable costs incurred in connection therewith. This cost will be averaged with the adjusted cost base of all other Trust Units held by the Unitholder at that time as capital property to determine the adjusted cost base to the Unitholder of each Trust Unit.

Upon the disposition or deemed disposition by a Unitholder of a Trust Unit, whether on redemption or otherwise, the Unitholder will generally realize a capital gain (or a capital loss) equal to the amount by which the proceeds of disposition (excluding any amount which represents an amount that must otherwise be included in the Unitholder's income as described above) are greater (or less) than the aggregate of the Unitholder's adjusted cost base of the Trust Unit and any reasonable costs of disposition.

Generally, one-half of any capital gain (a "taxable capital gain") realized by a Unitholder in a taxation year must be included in the Unitholder's income for the year, and one-half of any capital loss (an "allowable capital loss") realized by a Unitholder in a taxation year must be deducted from taxable capital gains realized by the Unitholder in that year. Allowable capital losses for a taxation year in excess of taxable capital gains for that year generally may be carried back and deducted in any of the three preceding taxation years or carried forward and deducted in any subsequent taxation year against net taxable capital gains realized in such years, to the extent and under the circumstances described in the Tax Act.

Where Trust Units are redeemed and property of the Trust is distributed in specie to a Unitholder on the redemption, the proceeds of disposition to the Unitholder of the Trust Units will generally be equal to the fair market value of the property so distributed less the amount of any income or capital gain realized by the Trust on the distribution of such property. The cost to a Unitholder of any property distributed to the Unitholder on a redemption of Trust Units will generally be equal to the fair market value of such property at the time of the distribution (less any accrued interest thereon in the case of Initial Notes). A Unitholder that receives Redemption Notes or Initial Notes will be required to include in income interest on the Initial Note or Redemption Note (including interest that had accrued to the date of the acquisition of the Initial Note by a Unitholder) in accordance with the provisions of the Tax Act. To the extent that a Unitholder is required to include in income any interest that had accrued to the date of the acquisition of the Initial Note, an offsetting deduction may be available.

A Unitholder that throughout the relevant taxation year is a "Canadian-controlled private corporation", as defined in the Tax Act, may be liable to pay an additional refundable tax of 6 2/3 percent on certain investment income, including taxable capital gains and certain income from the Trust.

Taxation of Debenture Holders

Interest on Debentures

A holder of Debentures that is a corporation, partnership, unit trust or any trust of which a corporation or a partnership is a beneficiary will be required to include in computing its income for a taxation year any interest on the Debentures that accrues to it to the end of the particular taxation year or that has become receivable by or is received by the holder before the end of that taxation year, except to the extent that such interest was included in computing the holder's income for a preceding taxation year.

Any other holder will be required to include in computing income for a taxation year all interest on the Debentures that is received or receivable by the holder in that taxation year (depending upon the method regularly followed by the holder in computing income), except to the extent that the interest was included in the holder's income for a preceding taxation year. In addition, if in a taxation year such a holder holds Debentures on any "anniversary day" thereof, the holder will be required to include in income for the year interest that has accrued to the holder to the end of that date on the Debentures, to the extent that the interest was not otherwise included in computing the income of the holder for the year or a preceding taxation year. For this purpose, the "anniversary day" of a Debenture means (i) the day that is one year after the day immediately preceding the date of its issue; (ii) the day that occurs at every successive one year interval from the day determined under (i); and (iii) the day upon which the Debenture was disposed of.

- 34 -

A holder of Debentures that throughout the relevant taxation year is a "Canadian-controlled private corporation", as defined in the Tax Act, may be liable to pay an additional refundable tax of 6 2/3 percent on certain investment income, including interest and taxable capital gains.

Exercise of Conversion Privilege

A holder of a Debenture who exchanges the Debenture for Trust Units pursuant to the conversion privilege will be considered to have disposed of the Debenture for proceeds of disposition equal to the aggregate of the fair market value of the Trust Units so acquired at the time of the exchange and the amount of any cash received in lieu of a fractional Trust Unit. The holder will realize a capital gain or capital loss computed as described below under "Other Dispositions of Debentures".

The cost to the holder of the Trust Units so acquired will be equal to their fair market value and must be averaged with the adjusted cost base of all other Trust Units held by the holder at the time as capital property for the purpose of calculating the adjusted cost base of each such Trust Unit.

Redemption or Repayment of Debentures

If the Trust redeems a Debenture prior to Maturity or repays a Debenture upon Maturity and the holder does not exercise the conversion privilege prior to such redemption or repayment, the holder will be considered to have disposed of the Debenture for proceeds of disposition equal to the amount received by the holder (other than the amount received as interest) on such redemption or repayment. If the holder receives Trust Units on redemption or repayment, the holder will be considered to have received proceeds of disposition equal to the fair market value of such Trust Units. The holder may realize a capital gain or capital loss computed as described below under "Other Dispositions of Debentures". The cost to the holder of the Trust Units so received will be equal to their fair market value and must be averaged with the adjusted cost base of all other Trust Units held by the holder at that time as capital property for the purpose of calculating the adjusted cost base of each such Trust Unit.

Other Dispositions of Debentures

A disposition or deemed disposition by a holder of a Debenture will generally result in the holder realizing a capital gain (or capital loss) equal to the amount by which the proceeds of disposition (adjusted as described below) are greater (or less) than the aggregate of the holder's adjusted cost base thereof and any reasonable costs of disposition. Any such capital gains or capital losses will be treated, for tax purposes, in the same manner as capital gains and capital losses arising from a disposition of Trust Units which treatment is discussed above under "Taxation of Unitholders".

Upon such a disposition or deemed disposition of a Debenture, interest accrued thereon to the date of disposition will be included in computing the holder's income, except to the extent such amount was otherwise included in the holder's income, and will be excluded in computing the holder's proceeds of disposition of the Debenture.

ELIGIBILITY FOR INVESTMENT

In the opinion of counsel, based on representations of Provident and the Trust as to certain factual matters, the Trust Units and Debentures offered hereunder will, on the date of closing of the offering, be qualified investments under the Tax Act and the regulations thereunder for trusts governed by registered retirement savings plans, registered retirement income funds, deferred profit sharing plans (other than, in the case of the Debentures, a deferred profit sharing plan for the benefit of employees of the Trust) and registered education savings plans and will not be foreign property for purposes of the Tax Act.

LEGAL MATTERS

Certain legal matters in connection with the issuance of the Trust Units and Debentures offered hereby will be passed upon on behalf of the Trust by Macleod Dixon LLP, Calgary, Alberta and on behalf of the Underwriters by Stikeman Elliott LLP, Calgary, Alberta.

- 35 -

AUDITORS, TRANSFER AGENT AND REGISTRAR

The auditors of the Trust are PricewaterhouseCoopers LLP, Chartered Accountants, 111 5^th Avenue S.W., Suite 3100, Calgary, Alberta, T2P 5L3.

The transfer agent and registrar for the Trust Units is Computershare Trust Company of Canada at its principal offices in Toronto, Ontario and Calgary, Alberta. The transfer agent and registrar for the Debentures will be Computershare Trust Company of Canada at its principal offices in Toronto, Ontario and Calgary, Alberta.

INTERESTS OF EXPERTS

As of the date hereof, the partners and associates of each of Macleod Dixon LLP and Stikeman Elliott LLP, as a group, beneficially own, directly or indirectly, less than one percent of the Trust Units. As of the date hereof, the principals of McDaniel & Associates Consultants Ltd., independent oil and gas reservoir engineers, as a group, beneficially own, directly or indirectly, less than one 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 one 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 one percent of the Trust Units. As of the date hereof, the principals of Gilbert Laustsen Jung Associates Ltd., independent oil and gas reservoir engineers, as a group, beneficially own, directly or indirectly, less than one percent of the Trust Units.

CONSENTS

Consent of PricewaterhouseCoopers LLP

We refer to the short form prospectus of Provident Energy Trust (the "Trust") dated June 28, 2004 relating to the qualification for distribution of 12,100,000 trust units and 50,000 debentures of the Trust (the "Prospectus"). We have complied with Canadian generally accepted standards for an auditor's involvement with offering documents.

We consent to the incorporation by reference in the above mentioned Prospectus of our report to the unitholders of the Trust on the audited consolidated balance sheets as at December 31, 2003 and 2002 and the consolidated statements of operations and accumulated income (loss) and cash flows for the years ended December 31, 2003 and 2002. Our report is dated March 11, 2004.

We also consent to the inclusion in the above mentioned Prospectus of our report dated June 28, 2004 to the Trustee of the Trust on the consolidated pro forma balance sheet as at March 31, 2004 and the consolidated pro forma statements of operations for the three month period ended March 31, 2004 and the year ended December 31, 2003.

We also consent to the incorporation by reference in the above mentioned Prospectus of our report to the shareholders of Olympia Energy Inc. on the audited consolidated balance sheets as at December 31, 2003 and 2002 and the consolidated statements of earnings and retained earnings and cash flows for the years then ended. Our report is dated March 5, 2004.

Calgary, Alberta	(Signed)PRICEWATERHOUSECOOPERS LLP
June 28, 2004	Chartered Accountants

Consent of Ernst & Young LLP

We have read the short form prospectus of Provident Energy Trust (the "Trust") dated June 28, 2004 relating to the qualification for distribution of 12,100,000 trust units and 50,000 debentures of the Trust (the "Prospectus"). We have complied with Canadian generally accepted standards for an auditor's involvement with offering documents.

We consent to the incorporation by reference in the above mentioned Prospectus of our report to the Board of Directors of Williams Energy (Canada), Inc. on the balance sheet of the Redwater Natural Gas Liquids Processing System, a segment of Williams Energy (Canada), Inc. as at December 31, 2002 and the statements of operations and cash flows for the year ended December 31, 2002. Our report is dated July 31, 2003.

- 36 -

System, a segment of Williams Energy (Canada), Inc. as at December 31, 2002 and the statements of operations and cash flows for the year ended December 31, 2002. Our report is dated July 31, 2003.

Calgary, Alberta	(Signed)ERNST & YOUNG LLP
June 28, 2004	Chartered Accountants

Consent of KPMG LLP

We have read the short form prospectus of Provident Energy Trust (the "Trust") dated June 28, 2004 relating to the qualification for distribution of 12,100,000 trust units and 50,000 debentures of the Trust (the "Prospectus"). We have complied with Canadian generally accepted standards for an auditor's involvement with offering documents.

We consent to the incorporation by reference in the above mentioned Prospectus of our report to the directors of Viracocha Energy Inc. on the audited consolidated balance sheets 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. Our report is dated April 27, 2004.

Calgary, Alberta	(Signed)KPMG LLP
June 28, 2004	Chartered Accountants

PURCHASERS' STATUTORY RIGHTS

Securities legislation in several of the provinces of Canada provides purchasers with the right to withdraw from an agreement to purchase securities. This right may be exercised within two business days after receipt or deemed receipt of a prospectus and any amendment. In several of the provinces, the securities legislation further provides a purchaser with remedies for rescission or, in some jurisdictions, damages if the prospectus and any amendment contains a misrepresentation or is not delivered to the purchaser, provided that such remedies for rescission or damages are exercised by the purchaser within the time limit prescribed by the securities legislation of the purchaser's province. The purchaser should refer to any applicable provisions of the securities legislation of the purchaser's province for the particulars of these rights or consult with a legal adviser.

- 37 -

SCHEDULE A

FINANCIAL STATEMENTS OF
BREITBURN ENERGY COMPANY LLC

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

BreitBurn Energy Company LLC
and Subsidiaries

Report on Audited Consolidated Financial Statements
For the Years Ended December 31, 2003 and 2002

A - 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

A - 2

BreitBurn Energy Company LLC
and Subsidiaries
Consolidated Balance Sheets
December 31, 2003 and 2002
		2003		2002
Assets
Current assets
Cash and cash equivalents	$	714,570	$	323,205
Accounts receivable
Trade, net of allowance for doubtful accounts of $42,054 and $49,097
as of December 31, 2003 and 2002, respectively		5,012,823		5,297,543
Other receivable		634,082		95,464
Prepaid expenses		653,984		781,607
Hedge asset				5,586
Deposits and other		166,030		176,030
Total current assets		7,181,489		6,679,435
Property, plant and equipment, net		96,845,940		110,554,876
Other assets
Abandonment bonds		100,000		75,075
Debt issuance costs, net of accumulated amortization of $910,088 and $642,032
as of December 31, 2003 and 2002, respectively		103,530		357,406
Investment in affiliates		581,691		309,036
Notes receivable related parties		500,000		500,000
Hedge asset				26,227
Other long-term assets		40,849		40,849
		1,326,070		1,308,593
Total assets	$	105,353,499	$	118,542,904
Liabilities and Members Equity
Current liabilities
Accounts payable and accrued liabilities	$	7,793,309	$	9,376,675
Hedge liability		6,180,066		3,798,213
Derivative settlements payable		862,653		473,800
Liability due to disposal of non-operating interest		2,000,000		500,000
Senior subordinated debt due to member		1,500,000		-
Current portion of long-term debt		37,400,000		-
Total current liabilities		55,736,028		14,148,688
Long-term debt		-		62,400,000
Senior subordinated long-term debt due to member		-		1,500,000
Abandonment liability		708,764		2,303,591
Hedge liability		3,120,805		879,586
Liability due to disposal of non-operating interest		1,500,000		3,500,000
Other long-term liability		1,130,000		1,270,000
Total liabilities		62,195,597		86,001,865
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		34,924,655
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)		14,673,782		2,262,370
Accumulated other comprehensive loss		(9,300,871)		(4,645,986)
Total members equity		5,372,911		(2,383,616)
Total liabilities and members equity	$	105,353,499	$	118,542,904

A - 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

A - 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)

A - 5

BreitBurn Energy Company LLC
and Subsidiaries
Consolidated Statements of Members Equity
For the Years Ended December 31, 2003 and 2002
					Accumulated
					Other
	Class A		Class B		Comprehensive
	Shares	Amount	Shares	Amount	Loss		Total
Balance at December 31, 2001	11,834,620	$ 1,764,288	749,625	$ -		$ 3,786,487	$ 5,550,775
Issuance of Class B common shares			117,500				-
Net income		4,509,613		272,440			4,782,053
Redeemable preferred stock accretion		(598,092)		(39,360)			(637,452)
Redeemable preferred cash dividend		(3,413,439)		(233,080)			(3,646,519)
Change in fair value of derivative instruments						(8,432,473)	(8,432,473)
Balance at December 31, 2002	11,834,620	2,262,370	867,125	-		(4,645,986)	(2,383,616)
Issuance of Class A common shares	334,698						-
Issuance of Class B common shares			92,000				-
Purchase of Class B common shares			(40,375)	(17,226)			(17,226)
Net income		16,124,490		987,742			17,112,232
Redeemable preferred stock accretion		(593,183)		(44,269)			(637,452)
Redeemable preferred stock cash dividend		(1,698,787)		(124,472)			(1,823,259)
Accrued preferred stock dividend		(2,065,386)		(157,497)			(2,222,883)
Change in fair value of derivative instruments						(4,654,885)	(4,654,885)
Balance at December 31, 2003	12,169,318	$ 14,029,504	918,750	$ 644,278		$ (9,300,871)	$ 5,372,911

A - 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

A - 7

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 ConsolidationThe 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 RecognitionOil and gas revenue is recognized when title passes to the customer.

Cash and Cash EquivalentsCash and cash equivalents include short-term investments with an original maturity of three months or less.

Oil and Gas PropertiesThe 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.

A - 8

BreitBurn Energy Company LLC

and Subsidiaries

Notes to Consolidated Financial Statements

2. Significant Accounting Policies (Continued)

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.

A - 9

BreitBurn Energy Company LLC

and Subsidiaries

Notes to Consolidated Financial Statements

2. Significant Accounting Policies (Continued)

Stock CompensationThe 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 AssetsOil 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. 143In 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.

A - 10

BreitBurn Energy Company LLC

and Subsidiaries

Notes to Consolidated Financial Statements

2. Significant Accounting Policies (Continued)

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 InstrumentsSFAS 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 TaxesThe 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 EstimatesThe 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.

ReclassificationsCertain items in the prior year financial statements have been reclassified to conform to the 2003 presentation.

A - 11

BreitBurn Energy Company LLC

and Subsidiaries

Notes to Consolidated Financial Statements

2. Significant Accounting Policies (Continued)

Management's PlanThe 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. 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 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.

A - 12

BreitBurn Energy Company LLC

and Subsidiaries

Notes to Consolidated Financial Statements

4. Property, Plant and Equipment

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

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.

A - 13

BreitBurn Energy Company LLC

and Subsidiaries

Notes to Consolidated Financial Statements

5. Notes Payable (Continued)

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

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.

A - 14

BreitBurn Energy Company LLC

and Subsidiaries

Notes to Consolidated Financial Statements

6. Members Equity (Continued)

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. 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 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. 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 $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.

A - 15

BreitBurn Energy Company LLC

and Subsidiaries

Notes to Consolidated Financial Statements

8. Commitments and Contingencies (Continued)

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. Related-Party Transactions

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.

A - 16

BreitBurn Energy Company LLC

and Subsidiaries

Notes to Consolidated Financial Statements

9. Related-Party Transactions (Continued)

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.

A - 17

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)

A - 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.

A - 19

BreitBurn Energy Company LLC
and SubsidiariesConsolidated Financial Statements
For the Three Month Periods Ended March 31, 2004 and 2003

A - 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

A - 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

A - 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

A - 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)

A - 24

BreitBurn Energy Company LLC
and Subsidiaries
Consolidated Statements of Cash Flows
(Unaudited)
		Three Months Ended
		March 31,
		2004		2003
Cash flows from operating activities
Net income (loss)	$	(399,877)	$	3,915,685
Adjustments to reconcile net income (loss) to net cash provided by
operating activities
Cumulative effect of accounting change		903,099		(1,653,303)
Depletion, depreciation and amortization		781,401		947,378
Amortization of debt issuance costs		67,013		67,014
Equity earnings in affiliate		(65,684)		(57,661)
Distributions received from affiliates		-		91,989
Gain on sales of assets		-		(900)
Changes in working capital
Increase in accounts receivable		(314,065)		(640,391)
(Increase) decrease in prepaid expenses, deposits and other		82,554		(62,688)
Increase in accounts payable and accrued liabilities		1,703,854		1,356,449
Net cash provided by operating activities		2,758,295		3,963,572
Cash flows from investing activities
Expenditures for oil and gas properties		(3,259,222)		(3,660,336)
Expenditures for land		-		(12,409)
Proceeds from sales of assets		-		900
Additions to non-oil and gas assets		(8,853)		(14,932)
Net cash used in investing activities		(3,268,075)		(3,686,777)
Cash flows from financing activities
Proceeds from long-term debt		19,600,000		12,400,000
Payments on long-term debt		(19,400,000)		(13,000,000)
Debt issuance costs		(404,790)		-
Net cash used in financing activities		(204,790)		(600,000)
Net decrease in cash and cash equivalents		(714,570)		(323,205)
Cash and cash equivalents
Beginning of year		714,570		323,205
End of period	$	0	$	0

A - 25

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.

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.

A - 26

BreitBurn Energy Company LLC

and Subsidiaries

Notes to Consolidated Financial Statements

2. 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.

A - 27

BreitBurn Energy Company LLC

and Subsidiaries

Notes to Consolidated Financial Statements

2. 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.

A - 28

BreitBurn Energy Company LLC

and Subsidiaries

Notes to Consolidated Financial Statements

2. 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.

A - 29

BreitBurn Energy Company LLC

and Subsidiaries

Notes to Consolidated Financial Statements

2. 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.

3. 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.

A - 30

BreitBurn Energy Company LLC

and Subsidiaries

Notes to Consolidated Financial Statements

3. 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.

4. Property, Plant and Equipment

Property, plant and equipment at March 31, 2004 and December 31, 2003 was as follows:

		March 31,	December 31,
		2003		2003
Proved oil and gas properties, successful efforts method	$	113,906,597	$	110,647,375
Land		1,990,384		1,990,384
Buildings		274,483		274,483
Non-oil and gas assets		1,166,346		1,157,493
		117,337,810		114,069,735
Less accumulated depletion, depreciation and amortization		(17,989,448)		(17,223,795)
Property, plant and equipment, net	$	99,348,362	$	96,845,940

There was no interest capitalized to oil and gas properties for the three month periods ended March 31, 2004 and 2003, respectively.

5. 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		Maturity
Senior Credit
Agreement	Various	Quarterly	$	2,600,000	$	6,400,000	May 5, 2004
Senior Credit
Agreement	Various	Monthly		31,000,000		31,000,000	May 5, 2004
Subordinated Credit
Agreement	Various	Monthly		4,000,000		-	June 1, 2004
Promissory Note	Various	Quarterly		1,500,000		1,500,000	March 25, 2004
			$	39,100,000	$	38,900,000

A - 31

BreitBurn Energy Company LLC

and Subsidiaries

Notes to Consolidated Financial Statements

5. 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).

A - 32

BreitBurn Energy Company LLC

and Subsidiaries

Notes to Consolidated Financial Statements

5. 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.

6. 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.

A - 33

BreitBurn Energy Company LLC

and Subsidiaries

Notes to Consolidated Financial Statements

7. 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.

8. 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	$	708,764
Reduction for wells sold		-
Accretion expense		15,748
Asset retirement obligations as of March 31, 2004	$	724,512

A - 34

BreitBurn Energy Company LLC

and Subsidiaries

Notes to Consolidated Financial Statements

8. 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 Ending
2004	$	305,883
2005		265,689
2006		7,604
2007		2,900
2008		-
	$	582,076

Rent expense for the three month periods ended March 31, 2004 and 2003 amounted to $83,525 and $83,312, respectively.

9. 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.

A - 35

BreitBurn Energy Company LLC

and Subsidiaries

Notes to Consolidated Financial Statements

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 three month periods ended March 31, 2004 and 2003, the matching contributions were $28,515 and $26,590, respectively.

11. 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.

12. 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.

A - 36

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:

	Three months ended		Three months ended
	March 31, 2004			March 31, 2003
Net income (loss) - US GAAP	$	(399,877)	$	3,915,685
Cumulative 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)	$	1,091,484

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

	March 31, 2004		December 31, 2003
	Canadian	U.S.	Canadian	U.S.
	GAAP	GAAP	GAAP	GAAP
Current liabilities
Hedge liability	-	8,485,839	-	6,180,066
Other liabilities
Hedge liability	-	6,169,609	-	3,120,805
Redeemable preferred shares	-	-	37,784,991	-
Equity
Redeemable preferred shares	-	-	-	37,784,991
Accumulated other
comprehensive loss	-	(14,655,448)	-	(9,300,871)

A - 37

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. 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.

A - 38

SCHEDULE B
UNAUDITED PRO FORMA CONSOLIDATED FINANCIAL STATEMENTS

COMPILATION REPORT

To the Trustee of
Provident Energy Trust

June 28, 2004

We have read the accompanying unaudited consolidated pro forma balance sheet of Provident Energy Trust (the Trust) as at March 31, 2004 and the unaudited consolidated pro forma statements of operations for the three months then ended and for the year ended December 31, 2003 and have performed the following procedures.

1. Compared the figures in the columns captioned "Provident Energy Trust" to the unaudited financial statements of the Trust as at March 31, 2004 and for the three months then ended, and the audited financial statements of the Trust for the year ended December 31, 2003, respectively, and found them to be in agreement.

2. Compared the figures in the column captioned "Redwater January 1, 2003 to June 30, 2003" to the unaudited financial statements of the Redwater natural gas liquids processing system, a segment of Williams Energy (Canada) Inc. ( Redwater ) for the period January 1, 2003 to June 30, 2003 and found them to be in agreement.

3. Compared the amounts in the column captioned Redwater July 1, 2003 to September 29, 2003 to the unaudited financial information of the Redwater natural gas liquids processing system, a segment of Williams Energy (Canada) Inc. ( Redwater ) for the period July 1, 2003 to September 29, 2003 and found them to be in agreement.

4. Compared the figures in the columns captioned Olympia to the unaudited financial statements of Olympia Energy Inc. as at and for the three months ended March 31, 2004 and the audited financial statements of Olympia Energy Inc. for the year ended December 31, 2003, respectively, and found them to be in agreement.
5. Compared the figures in the columns captioned Viracocha to the unaudited financial statements of Viracocha Energy Inc. as at and for the three months ended March 31, 2004 and the audited financial statements of Viracocha Energy Inc. for the year ended December 31, 2003, respectively, and found them to be in agreement.
6. Compared the figures in the columns captioned BreitBurn to the unaudited financial statements of BreitBurn Energy Company LLC as at and for the three months ended March 31, 2004 and the audited financial statements of BreitBurn Energy Company LLC for the year ended December 31, 2003 which have been appropriately translated to Canadian GAAP and Canadian dollars, respectively, and found them to be in agreement.

B - 1

7. Made enquiries of certain officials of the Trust who have responsibility for financial and accounting matters about:

1. the basis for determination of the pro forma adjustments; and
2. whether the pro forma financial statements comply as to form in all material respects with the Securities Acts of the various Provinces of Canada (the Acts ).

The officials:

1. described to us the basis for determination of the pro forma adjustments, and
2. stated that the pro forma statements comply as to form in all material respects with the Acts.

8. Read the notes to the pro forma statements, and found them to be consistent with the basis described to us for determination of the pro forma adjustments.

9. Recalculated the application of the BreitBurn, Olympia, Viracocha and Redwater pro forma adjustments to the aggregate of the amounts in the columns captioned "Provident Energy Trust , Olympia , Viracocha and BreitBurn for the year ended December 31, 2003 and "Redwater" for the periods applicable and found the amounts in the columns captioned Sub-total Redwater January 1 to September 29 , Total Provident , and Combined to be arithmetically correct.

10. Recalculated the application of the BreitBurn, Olympia and Viracocha pro forma adjustments to the aggregate of the amounts in the columns captioned Provident Energy Trust , Olympia , Viracocha and BreitBurn as at and for the three month period ended March 31, 2004 and found the amounts in the columns captioned Sub-total , Total Provident and Combined to be arithmetically correct.

A pro forma financial statement is based on management assumptions and adjustments which are inherently subjective. The foregoing procedures are substantially less than either an audit or a review, the objective of which is the expression of assurance with respect to management's assumptions, the pro forma adjustments, and the application of the adjustments to the historical financial information. Accordingly, we express no such assurance. The foregoing procedures would not necessarily reveal matters of significance to the pro forma financial statements, and we therefore make no representation about the sufficiency of the procedures for the purposes of a reader of such statements.

(Signed) PRICEWATERHOUSECOOPERS LLP

Chartered Accountants
Calgary, Alberta

B - 2

PROVIDENT ENERGY TRUST
PRO FORMA CONSOLIDATED STATEMENT OF OPERATIONS
For the year ended December 31, 2003 Canadian dollars (000s)
(unaudited)

		Redwater	Redwater	Redwater
	Provident	January 1, 2003	July 1, 2003	January 1, 2003
	Energy	to	to	to	Redwater		Olympia		Viracocha	Total		Breitburn
	Trust	June 30, 2003	Sept. 29, 2003	Sept. 29, 2003	Adjustments	Olympia	Adjustments	Viracocha	Adjustments	Provident	Breitburn	Adjustments	Combined
Revenue
Sales	473,571	350,694	143,945	494,639	-	48,418	-	47,731	(7,227)	1,057,132	43,217	929	1,101,278
Royalties	(72,869)	-	-	-	-	(8,866)	(500)	(9,651)	767	(91,119)	-	-	(91,119)
Gain on sale of assets	-	-	-	-	-	-	-	-	-	-	15,170	(k)(15,170)	-
Operating Fees	-	-	-	-	-	-	-	-	-	-	929	(929)	-
	400,702	350,694	143,945	494,639	-	39,552	(500)	38,080	(6,460)	966,013	59,316	(15,170)	1,010,159
Expenses
Cost of goods sold	153,147	318,734	117,881	436,615	-	-	-	-	-	589,672	-	-	589,672
Production, operating and maintenance	84,040	17,169	11,007	28,176	-	8,532	-	9,872	(2,102)	128,518	20,398	1,784	150,700
Gas and NGL purchases	-	-	-	-	-	-	-	-	-	-	133	(133)	-
Production and property taxes	-	-	-	-	-	-	-	-	-	-	1,651	(1,651)	-
Exploration and acquisition	-	-	-	-	-	-	-	-	-	-	26	(26)	-
General and administrative	16,670	4,234	1,542	5,776	-	3,511	786	2,090	107	28,940	5,846	-	34,786
Management internalization	18,592	-	-	-	-	-	-	-	-	18,592	-	-	18,592
Interest on bank debt	9,733	3,144	1,581	4,725	(3,575)	1,707	-	1,432	-	14,022	3,774	(3,774)	14,022
Interest income	--	-	-	-	-	-	-	-	-	-	(67)	-	(67)
Bad debt expense	-	8,418	-	8,418	-	-	-	-	-	8,418	-	-	8,418
Amortization of convertible debenture	-	-	-	-	-	-	-	107	(107)	-	-	-	-
Amortization of debt issuance costs	-	-	-	-	-	-	-	-	-	-	376	(376)	-
Other expense	-	-	-	-	-	-	-	-	-	-	527	-	527
Other income	-	-	-	-	-	-	-	-	-	-	(85)	-	(85)
Redeemable preferred stock accretion	-	-	-	-	-	-	-	-	-	-	893	(893)	-
Redeemable preferred cash dividend	-	-	-	-	-	-	-	-	-	-	2,555	(2,555)	-
Accrued preferred stock dividend	-	-	-	-	-	-	-	-	-	-	3,116	(3,116)	-
Depletion, depreciation and accretion	138,272	3,079	1,540	4,619	2,258	13,324	1,362	15,377	(2,306)	172,906	5,070	2,517	180,493
	420,454	354,778	133,551	488,329	(1,317)	27,074	2,148	28,878	(4,408)	961,158	44,213	(8,223)	997,148
Gain on sale of High Point shares	-	-	-	-	-	1,087	-	-	-	1,087	-	-	1,087
Income (loss) before taxes	(19,752)	(4,084)	10,394	6,310	1,317	13,565	(2,648)	9,202	(2,052)	5,492	15,103	(6,947)	14,098
Capital taxes	3,332	-	-	-	402	-	486	344	97	4,661	-	-	4,661
Current taxes	-	(117)	-	(117)	117	458	(458)	-	-	-	-	-	-
Withholding tax	-	-	-	-	-	-	-	-	-	-	-	(i)810	810
Future income tax expense (recovery)	(56,478)	(1,433)	4,365	2,392	(320)	110	(940)	1,741	(728)	53,683)	-	(i)3,576	50,107)
	(53,146)	(1,550)	4,365	2,815	199	568	(912)	2,085	(631)	49,022)	-	4,386	44,636)
Non-controlling interest	-	-	-	-	-	-	-	-	-	-	-	652	652
Net income (loss) for the period	33,394	(2,534)	6,029	3,495	1,118	12,997	(1,736)	7,117	(1,421)	54,964	15,103	(11,985)	58,082
Net income per unit - basic	0.38									0.38			(l)0.34
Net income per unit - diluted	0.38									0.38			(l)0.34

B - 3

PROVIDENT ENERGY TRUST
CONSOLIDATED PRO FORMA BALANCE SHEET
As at March 31, 2004 Canadian dollars (000s)
(unaudited)

	Provident
	Energy		Olympia		Viracocha			Breitburn
	Trust	Olympia	adjustments	Viracocha	adjustments	Sub-total	Breitburn	adjustments	Combined
Assets
Current assets
Cash	$ 92	$ 2	$ -	$ -	$ -	$ 94	$ -	$ -	$ 94
Accounts receivable	132,280	10,131	-	6,152	2,400	150,963	7,195	-	158,158
Other receivable	-	10	-	-	-	10	622	-	632
Petroleum product inventory	14,037	-	-	-	-	14,037	-	-	14,037
Deferred derivative loss	18,542	-	-	-	-	18,542	-	-	18,542
Prepaids	5,745	574	-	555	-	6,874	707	-	7,581
Deposits and other	-		-	-	-	-	231	-	231
	170,696	10,717	-	6,707	2,400	190,520	8,755	-	199,275
Cash reserve for future site reclamation	2,095	-	-	-	-	2,095	-	-	2,095
Goodwill	102,443	-	(a)102,717	6,484	(a)118,190	329,834	-	-	329,834
Property, plant and equipment	862,697	153,523	(a)8,829	131,008	(a)(21,101)	1,134,956	130,275	78,645	1,343,876
Other assets
Abandonment bonds	-	-	-	-	-	-	197	-	197
Debt issuance costs, net of accum-amortization	-	-	-	-	-	-	578	(578)	-
Investment in affiliates	-	-	-	-	-	-	813	-	813
Notes receivable - related parties	-	-	-	-	-	-	656	-	656
Other long-term assets	-	-	-	-	-	-	54	-	54
	-	-	-	-	-	-	2,298	(578)	1,720
	$ 1,137,931	$164,240	$ 111,546	$144,199	$99,489	$1,657,405	$141,328	$78,067	$1,876,800

B - 4

PROVIDENT ENERGY TRUST
CONSOLIDATED PRO FORMA BALANCE SHEET
As at March 31, 2004 Canadian dollars (000s)(unaudited)

	Provident
	Energy		Olympia		Viracocha			Breitburn
	Trust	Olympia	adjustments	Viracocha	adjustments	Sub-total	Breitburn	adjustments	Combined
Liabilities
Current liabilities
Accounts payable and accrued liabilities	$ 136,284	$ 17,453	$ 3,400	$ 9,881	$ 138	$ 167,156	$ 12,026	$ 8,069	$ 187,251
Hedge liability	-	-	-	-	-	-	-	24,915	24,915
Derivative settlements payable	-	-	-	-	-	-	1,402	-	1,402
Liability due to disposal of non-operating interest	-	-	-	-	-	-	3,934	-	3,934
Senior subordinated debt due to member	-	-	-	-	-	-	1,967	(1,967)	-
Bank debt	-	49,194	(c)(49,194)	49,786	(c)(49,786)	-	49,305	(49,305)	-
Capital tax payable	-	-	-	138	(138)	-	-	-	-
Cash distribution payable	9,169	-	-	-	-	9,169	-	-	9,169
Non-Hedging derivative instrument	40,586	538	-	-	-	41,124	-	-	41,124
Redeemable preferred shares	-	-	-	-	-	-	50,732	(50,732)
	186,039	67,185	(45,794)	59,805	(49,786)	217,449	119,366	(69,020)	267,795
Hedge liability	-	-	-	-	-	-	-	-	-
Liability due to disposal of non-operating interest	-	-	-	-	-	-	-	-	-
Other long-term liability	-	-	-	-	-	-	2,296	(2,296)	-
Long-term debt	178,800	-	(c)49,194	2,976	(c)49,786	280,756	-	(12,396)	268,360
Capital lease obligation	-	-	-	84	-	84	-	-	84
Deferred lease obligation	-	-	-	112	-	112	-	-	112
Asset retirement obligation	33,023	1,834	-	7,763	-	42,620	949	-	43,569
Future income taxes	44,256	33,797	5,988	14,336	2,005	100,382	-	-	100,382
Unitholders' Equity
Unitholders' contributions	858,644	-	148,848	-	141,873	1,149,365	-	119,048	1,268,413
Members equity	-	-	-	-	-	-	18,717	(18,717)	-
Non-controlling interest	-	-	-	-	-	-	-	(j)13,448	13,448
Capital stock	-	21,658	(21,658)	52,251	(52,251)-	-	-	-	-
Exchangeable shares	17,441	-	14,734	-	14,734	46,909	-	-	46,909
Convertible debentures	119,377	-	-	-	-	119,377	-	48,000	167,377
Contributed surplus	870	1,124	(1,124)	423	(423)	870	-	-	870
Accumulated (loss)/retained earnings	(6,280)	38,642	(38,642)	6,449	(6,449)	(6,280)	-	-	(6,280)
Accumulated cash distributions	(279,054)	-	-	-	-	(279,054)	-	-	(279,054)
Accumulated interest on convertible debentures	(15,185)	-	-	-	-	(15,185)	-	-	(15,185)
	695,813	61,424	102,158	59,123	97,484	1,016,002	18,717	161,779	1,196,498
	$ 1,137,931	$164,240	$ 111,546	$ 144,199	$ 99,489	$1,657,405	$141,328	$78,067	$1,876,800

B - 5

PROVIDENT ENERGY TRUST
PRO FORMA CONSOLIDATED STATEMENT OF OPERATIONS
For the three months ended March 31, 2004 Canadian dollars (000s)(unaudited)

	Provident
	Energy		Olympia		Viracocha	Total		Breitburn
	Trust	Olympia	Adjustments	Viracocha	adjustments	Provident	Breitburn	adjustments	Combined
Revenue
Sales, net of royalties	266,647	(e)15,953	(3,309)	12,898	(e)(1,247)	292,046	12,257	190	303,389
					1,104				-
Realized loss on non-hedging derivative instruments	(9,656)	-	(73)	-	(1,104)	(10,833)	(3,623)	-	(14,456)
Unrealized loss on non-hedging derivative instruments	(22,044)	(h)(538)	-	-	-	(22,582)	-	-	(22,582)
Royalties	-	(g)(3,257)	3,257	-	-	-	-	-	-
Operating fees	-	-	-	-	-	-	190	(190)	-
	234,947	12,158	(125)	12,898	(1,247)	258,631	8,824	-	267,455
Expenses
Cost of goods sold	180,536	-	-	-	-	180,536	-	-	180,536
Production, operating and maintenance	27,548	2,653	-	3,461	(413)	33,249	4,350	409	38,008
Transportation	1,234	-	-	-	-	1,234	-	-	1,234
Gas and NGL purchases	-	-	-	-	-	-	35	(35)	-
Production and property taxes	-	-	-	-	-	-	374	(374)	-
Exploration and acquisition	-	-	-	-	-	-	-	-	-
General and administrative	4,831	801	-	689	-	6,321	1,312	-	7,633
Stock based compensation	-	164	-	-	-	164	-	-	164
Interest on bank debt	2,144	496	-	625	-	3,265	845	(845)	3,265
Interest income	-	-	-	-	-	-	(5)	-	(5)
Bad debt expense	-	-	-	-	-	-	-	-	-
Amortization of convertible debenture	-	-	-	8	-	8	-	-	8
Amortization of debt issuance costs	-	-	-	-	-	-	88	-	88
Other expense	-	-	-	-	-	-	153	-	153
Other income	-	-	-	-	-	-	(20)	-	(20)
Redeemable preferred stock accretion	-	-	-	-	-	-	781	(781)	-
Accrued preferred stock dividend	-	-	-	-	-	-	409	(409)	-
Depletion, depreciation and accretion	34,449	5,389	(d)370	5,778	(d)(2,206)	43,780	1,030	(d)881	45,691
	250,742	9,503	370	10,561	(2,619)	268,557	9,352	(1,154)	276,755
Income (loss) before taxes	(15,795)	2,655	(495)	2,337	1,372	(9,926)	(528)	1,154	(9,300)
Capital taxes	1,005	-	795	74	-	1,874	-	-	1,874
Current taxes	-	795	(795)	-	-	-	-	-	-
Withholding tax	-	-	-	-	-	-	-	203	203
Future income tax expense (recovery)	(14,549)	(622)	(f)(176)	498	(f)487	(14,362)	-	(274)	(14,088)
	(13,544)	173	(176)	572	487	(12,488)	-	(477)	(12,011)
Non-controlling interest	-	-	-	-	-	-	-	(j)(50)	(104)
Net income (loss) for the period	(2,251)	2,482	(319)	1,765	885	2,562	(528)	(627)	2,661
Net income (loss) per unit - basic	(0.06)	-	-	-	-	Nil	-	-	(0.01)
Net income (loss) per unit - diluted	(0.06)	-	-	-	-	Nil	-	-	(0.01)

B - 6

PROVIDENT ENERGY TRUST

NOTES TO UNAUDITED PRO FORMA CONSOLIDATED FINANCIAL STATEMENTS

March 31, 2004

(in thousands of Canadian dollars)

1. Basis of Presentation

The pro forma consolidated financial statements of Provident Energy Trust ("Provident") have been prepared by management to give effect to the purchase of the Redwater natural gas liquids processing system ("Redwater") from Williams Energy (Canada), Inc. the purchase of Viracocha Energy Inc. ( Viracocha ) and Olympia Energy Inc. ( Olympia ) which have been involved in oil and gas exploration, development and production in Canada, and to give effect to the purchase

of Breitburn Energy Company LLC and Subsidiaries ( Breitburn ), which is involved in oil and gas exploration, development and production in the United States. The Redwater assets are comprised of the extraction and fractionation assets of the Redwater facility, a liquids gathering system and the Younger plant. These pro forma consolidated financial statements have been prepared for inclusion in the prospectus for Provident dated June •, 2004.

The March 31, 2004 pro forma consolidated statement have been prepared from:

Provident's unaudited consolidated financial statements as at and for the three months ended March 31, 2004.

Breitburn s unaudited consolidated financial statements as at and for the three months ended March 31 2004 with related adjustments.

Viracocha's unaudited consolidated financial statements as at March 31, 2004 and for the three months then ended with related adjustments.

Olympia s unaudited consolidated financial statements as at March 31, 2004 and for the three months then ended with related adjustments.

The December 31, 2003 pro forma consolidated statement of operations has been prepared from:

Provident's audited consolidated financial statements as at and for the year ended December 31, 2003.

Breitburn s audited consolidated financial statements as at December 31, 2003 and for the year then ended with related adjustments.

Viracocha's audited consolidated financial statements as at December 31, 2003 and for the year then ended with related adjustments.

Olympia s audited consolidated financial statements as at December 31, 2003 and for the year then ended with related adjustments.

B - 7

The unaudited financial statements of Redwater for the six months ended June 30, 2003 with related adjustments.

The unaudited records of Redwater for the period July 1 to September 29, 2003.

In the opinion of the management of Provident, the pro forma consolidated financial statements include all adjustments necessary for fair presentation. The March 31, 2004 pro forma consolidated balance sheet gives effect to the transactions, except Redwater, as if the transactions occurred on March 31, 2004; the March 31, 2004 and December 31, 2003 pro forma consolidated statement of operations gives effect to the transactions as if they occurred on January 1, 2003.

The pro forma consolidated financial statements may not be indicative of the results of operations of the Trust which will be obtained upon completion of the arrangements. In preparing the pro forma consolidated financial statements, no adjustments have been made to reflect any operating or administrative cost savings that may have been achieved prior to the acquisition dates that may result from the operations of the combined assets. The purchase price allocations for Viracocha, Olympia and Breitburn are based on estimates and the actual allocation could vary from these estimates.

The pro forma consolidated financial statements should be read in conjunction with the financial statements, as listed in note 1.

2. Redwater Purchase

On September 30, 2003, Provident acquired Western Canadian midstream assets ( Redwater ) for $298.6 million. The purchase price was financed through $35.8 million of long-term debt, $71.8 million of net proceeds from the issuance of convertible debentures, and $191.1 million in net proceeds from the issuance of 19,205,000 trust units.

Provident allocated the purchase price of Redwater as follows:

Net assets 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:
Long-term debt	$	35,768
Issuance of trust units (net of costs $10,582)		191,070
Issuance of convertible debentures (net of costs of $3,200)		71,800
	$	298,638

3. Acquisition of Viracocha

On April 6, 2004 Provident entered into an agreement to acquire Viracocha for consideration of 12,758,386 Trust units and 1,325,000 exchangeable shares with a fair value of $156.6 million. The transaction has been accounted for using the purchase method with the allocation of the purchase price as follows:

NET ASSETS ACQUIRED AND LIABILITIES ASSUMED
Goodwill	$	124,673
Property, plant and equipment		109,907
Working capital deficiency		(3,311)
Bank debt		(52,762)
Capital lease obligation		(84)
Deferred lease obligation		(112)
Asset retirement obligation		(7,763)
Future income taxes		(16,341)
	$	154,207
CONSIDERATION
Acquisition costs	$	9,000
Option and warrant proceeds		(11,400)
Exchangeable shares		14,734
Trust units issued		141,873
	$	154,207

B - 8

4. Acquisition of Olympia

On April 6, 2004 Provident entered into an agreement to acquire Olympia for consideration of 13,385,579 Trust units and 1,325,000 exchangeable shares with a fair value of $163.6 million. The transaction has been accounted for using the purchase method with the allocation of the purchase price as follows:

NET ASSETS ACQUIRED AND LIABILITIES ASSUMED
Goodwill	$	102,717
Property, plant and equipment		162,352
Working capital deficiency		(6,736)
Bank debt		(49,194)
Asset retirement obligation		(1,834)
Non-hedging derivative instrument		(538)
Future income taxes		(39,785)
	$	166,982
CONSIDERATION
Acquisition costs	$	8,700
Option and warrant proceeds		(5,300)
Exchangeable shares		14,734
Trust units issued		148,848
	$	166,982

5. Acquisition of Breitburn

On June 15, 2004 Provident entered into an agreement to acquire Breitburn for consideration of $154.7 million. Provident is financing the acquisition with a bridge loan which will be paid with the proceeds of this prospectus. 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 & equipment	$	208,920
Working capital deficiency		(8,607)
Financial instruments		(24,915)
Abandonment bonds		197
Investment in affiliates		813
Notes receivable - related parties		656
Other long-term assets		54
Non-controlling interest		(13,448)
Abandonment liability		(949)
	$	162,721
CONSIDERATION
Acquisition costs	$	8,069
Cash		154,652
	$	162,721

6. Pro Forma Adjustments and Assumptions

1. The pro forma financial statements have been prepared as if Chamaelo Energy Inc. commenced operations on January 1, 2003 and the results of its operations have been eliminated. Accrete Energy Inc, operations were nil for 2004 and 2003. The two companies were spun out of Viracocha and Olympia prior to acquisition.
    

2. Interest on the cash portion of the acquisitions has been calculated using Provident's weighted average interest rate of 4.4%.

B - 9

3. Short-term debt has been reclassified to long-term debt as Olympia s and Viracocha s debt was replaced by the Trust s syndicated long-term debt. Breitburn's debt and preferred shares were assumed to be repaid from the proceeds of the prospectus.
    

4. Depletion and depreciation has been adjusted to reflect the pro forma value of the oil and gas assets, as if the acquisitions had occurred at the beginning of the period. In addition, depletion was adjusted to convert Breitburn from successful efforts to full cost.
    

5. Alberta Royalty Tax Credits have been reduced to reflect the maximum claim allowed under association rules.
    

6. The taxes on Canadian incremental income are assumed to be passed on to the unitholders. The future income tax expense on Canadian operations has been adjusted to reflect the impact on earnings of these adjustments at Provident s substantially enacted corporate rate of 35.5%.
    

7. Royalties with respect to Olympia have been reclassified to Revenue, net of royalties to be consistent with Provident's disclosure.
    
8. Realized losses on non-hedging derivative instruments with respect to Olympiahave been reclassified from Revenue net of royalties to be consistent with Provident's disclosure.

9. Withholding taxes on U.S. operations are estimated to be 10% on interest payments on inter-company debt and 5% on inter-company dividends. Taxes on U.S. operations of Breitburn are based on a combined federal and state tax rate of 43.8%.
    

10. Non-controlling interests will own 8% of the outstanding shares of the U.S. entity.
     
11. Breitburn's gain on sale of assets as recorded under successful efforts was eliminated to be consistent with Provident's policy of full cost.
     

12. The pro forma net loss per trust unit for the three months ended March 31, 2004 was $0.01 per unit. Net loss in the basic per trust unit calculations has been reduced by pro forma interest on convertible debentures. The pro forma financial statements were calculated based on 128,934,782 weighted average number of units outstanding during the period. On a diluted basis, net loss for the three months ended March 31, 2004 was $0.01 per unit and was calculated using an additional 142,924 trust units for the dilutive 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. If all convertible debentures were converted, an additional 15,950,006 trust units would be outstanding for a total of 145,027,712 diluted units outstanding.

The pro forma net income per trust unit for the year ended December 31, 2003 was $0.32 per unit. Net income in the basic per trust unit calculations has been reduced by pro forma interest on convertible debentures. The pro forma financial statements were calculated based on 123,701,881 weighted average number of units outstanding during the period. On a diluted basis, net loss for the year ended March 31, 2004 was $0.32 per unit and was calculated using an additional 50,098 trust units for the dilutive 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. If all convertible debentures were converted, an additional 15,680,611 trust units would be outstanding for a total of 139,432,590 diluted units outstanding.

B - 10

7. Translation of Financial Statements

The following schedules translate Breitburn financial statements from U.S. dollar, U.S. GAAP to Canadian dollar, Canadian GAAP statements.

Provident Energy Ltd.
Pro Form Consolidated Financial Statements
Balance sheet of Breitburn Energy Company LLC and Subsidiaries
As at March 31, 2004
(unaudited)
(000s) unless otherwise noted
	U.S.	GAAP	Canadian	Exchange	Canadian
	GAAP	Adjustments	GAAP	rate	GAAP
	US$	US$	US$	(i)	CAD$
Assets
Current assets
Cash and cash equivalents	-	-	-	1.3113	-
Accounts receivable	5,487	-	5,487	1.3113	7,195
Other receivable	474	-	474	1.3113	622

U.S.	GAAP	Canadian	Exchange	Canadian
GAAP	Adjustments	GAAP	rate	GAAP
US$	US$	US$	(i)	CAD$

Prepaid expenses	539	-	539	1.3113	707
Deposits and other	176	-	176	1.3113	231
Total current assets	6,676	-	6,676	1.3113	8,755
Property, plant and equipment, net	99,348	-	99,348	1.3113	130,275
Other assets
Abandonment bonds	150	-	150	1.3113	197
Debt issuance costs, net of accumulated	441	-	441	1.3113	578
amortization
Investment in affiliates	620	-	620	1.3113	813
Notes receivable - related parties	500	-	500	1.3113	656
Other long-term assets	41	-	41	1.3113	54
	1,752	-	1,752	1.3113	2,298
Total assets	107,776	-	107,776	1.3113	141,328

B - 11

7. Translation of Financial Statements (continued)

	U.S.	GAAP	Canadian	Exchange	Canadian
	GAAP	Adjustments	GAAP	rate	GAAP
	US$	US$	US$	(i)	CAD$
Liabilities and members' equity
Current liabilities
Accounts payable and accrued liabilities	9,170	-	9,170	1.3113	12,026
Hedge liability	8,486	(8,486)	-	1.3113	-
Derivative settlements payable	1,069	-	1,069	1.3113	1,402
Liability due to disposal of non-operating	3,000	-	3,000	1.3113	3,934
interest
Senior subordinated debt due to member	1,500	-	1,500	1.3113	1,967
Redeemable preferred shares	38,688	-	38,688	1.3113	50,732
Current portion of long-term debt	37,600	-	37,600	1.3113	49,305
Total current liabilities	99,513	(8,456)	91,027	1.3113	119,366
Abandonment liability	724	-	724	1.3113	949
Hedge liability	6,170	(6,170)	-	1.3113	-
Other long-term liability	1,751	-	1,751	1.3113	2,296
Total liabilities	108,158	(14,656)	93,502	1.3113	122,611
Members equity	14,274	-	14,274	1.3113	18,717
Accumulated other comprehensive loss	(14,656)	14,656	-	1.3113	-
Total members' equity	(382)	14,656	14,274	1.3113	18,717
Total liabilities and members' equity	107,776	-	107,776	1.3113	141,328
(i) Spot rate at March 31, 2004

B - 12

7. Translation of Financial Statements (continued)

Provident Energy Ltd.
Pro Form Consolidated Financial Statements
Statement of Operations of Breitburn Energy Company LLC and Subsidiaries
For the three months ended March 31, 2004
(unaudited)
(000s) unless otherwise noted

	U.S.	GAAP	Canadian	Exchange	Canadian
	GAAP	Adjustments	GAAP	rate	GAAP
	US$	US$	US$	(i)	CAD$
Revenues
Oil and gas sales	6,452	2,849	9,301	1.3178	12,257
Realized hedge loss	-	(2,749)	(2,749)	1.3178	(3,623)
Equity earnings in affiliate	66	(66)	-	1.3178	-
Operating fees	144	-	144	1.3178	190
	6,662	34	6,696	1.3178	8,824
Operating costs and expenses
Gas and NGL purchases	27		27	1.3178	35
Lease operating expenses	3,267	34	3,301	1.3178	4,350
Production and property taxes	284	-	284	1.3178	374
Depletion, depreciation and
amortization	735	-	735	1.3178	969
Exploration and acquisition
expense	-	-	-	1.3178	-
General and administrative	995	-	995	1.3178	1,312
	5,308	34	5,342	1.3178	7,040
Operating income	1,354	-	1,354	1.3178	1,784
Other (income) expense
Interest expense	641	-	641	1.3178	845
Redeemable preferred stock
accretion	-	593	593	1.3178	781
Accrued preferred stock dividend	-	310	310	1.3178	409
Interest income	(4)	-	(4)	1.3178	(5)
Amortization of debt issuance
costs	67	-	67	1.3178	88
Deprecation of non-oil and gas
assets	46	-	46	1.3178	61
Other expense	116	-	116	1.3178	153
Other income	(15)	-	(15)	1.3178	(20)
	850	903	1,753	1.3178	2,312
Income before cumulative effect of
accounting change	503	(903)	(400)	1.3178	(528)
Cumulative effect of accounting
change	(903)	903	-	1.3178	-
Net income	(400)	-	(400)	1.3178	(528)

 (i) Average exchange rate for the three moths ended March 31, 2004

B - 13

7. Translation of Financial Statements (continued)

Provident Energy Ltd.
Pro Form Consolidated Financial Statements
Statement of Operations of Breitburn Energy Company LLC and Subsidiaries
For the year ended December 31, 2003 (unaudited)
(000s) unless otherwise noted

	U.S.	GAAP	Canadian	Exchange	Canadian
	GAAP	Adjustments	GAAP	rate	GAAP
	US$	US$	US$	(i)	CAD$
Revenues
Oil and gas sales	30,461	375	30,836	1.4015	43,217
Gain on sale of assets	10,824	-	10,824	1.4015	15,170
Equity earnings in affiliate	233	(233)	-	1.4015	-
Operating fees	663	-	663	1.4015	929
	42,181	142	42,323	1.4015	59,316
Operating costs and expenses
Gas and NGL purchases	95	-	95	1.4015	133
Lease operating expenses	14,413	142	14,555	1.4015	20,398
Production and property taxes	1,178	-	1,178	1.4015	1,651
Depletion, depreciation and amortization	3,414	-	3,414	1.4015	4,784
Exploration and acquisition expense	19	-	19	1.4015	26
General and administrative	4,171	-	4,171	1.4015	5,846
	23,289	142	23,431	1.4015	32,839
Operating income	18,892	-	18,892	1.4015	26,477
Other (income) expense
Interest expense	2,693	-	2,693	1.4015	3,774
Redeemable preferred stock accretion	-	637	637	1.4015	893
Redeemable preferred cash dividend	-	1,823	1,823	1.4015	2,555
Accrued preferred stock dividend	-	2,223	2,223	1.4015	3,116
Interest income	(48)	-	(48)	1.4015	(67)
Amortization of debt issuance costs	268	-	268	1.4015	376
Depreciation of non-oil and gas assets	204	-	204	1.4015	286
Other expense	376	-	376	1.4015	527
Other income	(60)	-	(60)	1.4015	(85)
	3,433	4,683	8,116	1.4015	11,374
Income	15,459	(4,683)	10,776	1.4015	15,103
Cumulative effect of accounting change	1,653	(1,653)	-	1.4015	-
Net income	17,112	(6,336)	10,776	1.4015	15,103
(i) Average exchange rate for the year ended December 31, 2003

B - 14

7. Translation of Financial Statements (continued)

Hedge liability

Canadian GAAP does not require effective hedges to be marked to market and charged to other comprehensive income. Hedge losses have been reclassed out of sales and into realized hedge loss.

Redeemable preferred shares

Canadian GAAP requires Redeemable preferred shares to be recorded as debt. For U.S. GAAP, the accounting was harmonized in 2004. The only difference adjusted for in 2004 was the classification of the change in accounting policy

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

Equity earnings in affiliate

Canadian GAAP requires the Equity earnings in an affiliate to be proportionately consolidated.

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.

B - 15

CERTIFICATE OF PROVIDENT ENERGY TRUST

Date: June 28, 2004

This short form prospectus, together with the documents incorporated herein by reference, constitutes full, true and plain disclosure of all material facts relating to the securities offered by this short form prospectus as required by the securities legislation of each of the provinces of Canada. For the purpose of the Province of Québec, this simplified prospectus, as supplemented by the permanent information record, contains no misrepresentation that is likely to affect the value or the market price of the securities to be distributed.

PROVIDENT ENERGY TRUST

By: PROVIDENT ENERGY LTD.
(Signed) THOMAS W. BUCHANAN	(Signed) MARK N. WALKER
Chief Executive Officer	Vice President, Finance,
	Chief Financial Officer and
	Corporate Secretary
On behalf of the Board of Directors
(Signed) GRANT D. BILLING	(Signed) M.H. (MIKE) SHAIKH
Director	Director

C - 1

CERTIFICATE OF THE UNDERWRITERS

Date: June 28, 2004

To the best of our knowledge, information and belief, this short form prospectus, together with the documents incorporated herein by reference, constitutes full, true and plain disclosure of all material facts relating to the securities offered by this short form prospectus as required by the securities legislation of each of the provinces of Canada. For the purpose of the Province of Québec, to our knowledge, this simplified prospectus, as supplemented by the permanent information record, contains no misrepresentation that is likely to affect the value or the market price of the securities to be distributed.

BMO NESBITT BURNS INC.	NATIONAL BANK FINANCIAL INC.	TD SECURITIES INC.
By: (Signed) JASON J. ZABINSKY	By: (Signed) ROBERT B. WONNACOTT	By: (Signed) GREGORY B. SAKSIDA
	SCOTIA CAPITAL INC.
	By: (Signed) MARK HERMAN
	RBC DOMINION SECURITIES INC.
	By: (Signed) TIMOTHY W. WATSON
	CANACCORD CAPITAL CORPORATION
	By: (Signed) KARL B. STADDON
DESJARDINS SECURITIES INC. HSBC SECURITIES		(CANADA) INC.
By: (Signed) JAKE		A. HERMAN By: (Signed) DEBORAH J. SIMKINS

C - 2