UNITED STATES 

SECURITIES AND EXCHANGE COMMISSION 

Washington, D.C. 20549 

FORM 40-F 

(Check one)

o	REGISTRATION STATEMENT PURSUANT TO SECTION 12 OF THE SECURITIES EXCHANGE ACT OF 1934
	OR
þ	ANNUAL REPORT PURSUANT TO SECTION 13(A) OR 15(D) OF THE SECURITIES EXCHANGE ACT OF 1934

For the fiscal year ended December 31, 2004

Commission file number 1-15196

PROVIDENT ENERGY TRUST

  (Exact name of Registrant as specified in its charter)

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

Suite 800, 112 - 4th Avenue S.W., Calgary, Alberta, Canada T2P 0H3
(403) 296-2233

(Address and telephone number of Registrant’s principal executive offices) 

Dorsey & Whitney LLP

250 Park Avenue, New York, NY 10177-1500

(212) 415-9200

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

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

Title of each class Trust Units Name of each exchange on which registered American Stock Exchange

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

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

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

þ  Annual information form þ  Audited annual financial statements

Indicate the number of outstanding shares of each of the issuer’s classes of capital or common stock as of the close of the period covered by the annual report: 188,665,788

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

 Yes o  No þ

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

 Yes þ  No o

FORM 40-F

Principal Documents

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

(a)	Annual Information Form for the fiscal year ended December 31, 2005;
(b)	Management's Discussion and Analysis of Financial Condition and Results of Operations for the fiscal year ended December 31, 2005; and
(c)	Consolidated Financial Statements for the fiscal year ended December 31, 2005 (Note 20 to the Consolidated Financial Statements relates to United States Accounting Principles and Reporting (U.S. GAAP)).

RENEWAL ANNUAL INFORMATION FORM

For the year ended December 31, 2005

March 29, 2006

TABLE OF CONTENTS

	Page		Page
GLOSSARY OF TERMS	1	OIL AND NATURAL GAS OPERATIONS	29
ABBREVIATIONS, TERMS AND		NATURAL GAS MIDSTREAM, NGL
CONVERSIONS	5	PROCESSING AND MARKETING OPERATIONS	29
PRESENTATION OF OIL AND GAS		General	29
RESERVES AND PRODUCTION		NGL Extraction	29
INFORMATION	5	NGL Fractionation	30
NON-GAAP MEASURES	6	NGL Transportation	30
NOTE REGARDING FORWARD LOOKING		NGL Storage	30
STATEMENTS	6	NGL Marketing	30
INCORPORATION AND STRUCTURE	8	Commercial Arrangements	31
The Trust	8	Midstream services and marketing
Provident	8	assets	32
Provident Holdings Trust	8	Midstream and marketing services	33
Provident Acquisitions L.P	8	MARKET FOR SECURITIES	34
Provident Midstream L.P	8	RECORD OF CASH DISTRIBUTIONS	36
Provident Acquisitions Inc	9	DIRECTORS AND OFFICERS	37
Provident Midstream Inc	9	AUDIT COMMITTEE INFORMATION	42
Pro Holding Company	9	INFORMATION CONCERNING THE OIL
Breitburn Energy Company L.P	9	AND GAS INDUSTRY	44
INTERCORPORATE RELATIONSHIPS	9	RISK FACTORS	46
Provident Energy Trust	11	Oil and Gas Production Risk Factors	46
Provident Energy Ltd	17	Natural Gas Midstream, NGL
Provident Holdings Trust, Provident		Processing and Marketing
Acquisitions L.P., Provident		Business Risk Factors	48
Marketing L.P. and Provident		General Risk Factors	51
Midstream L.P	19	INTERESTS OF MANAGEMENT AND
Provident Acquisitions Inc	19	OTHERS IN MATERIAL
Provident Midstream Inc	19	TRANSACTIONS	55
Breitburn Energy Company L.P	19	TRANSFER AGENT AND REGISTRAR	55
Pro Holding Company	20	INTERESTS OF EXPERTS	55
Internalization of Management	20	MATERIAL CONTRACTS	55
GENERAL DEVELOPMENT OF THE		DOCUMENTS INCORPORATED BY REFERENCE
BUSINESS OF THE TRUST AND		REFERENCE	55
PROVIDENT	21	PRINCIPAL HOLDERS OF TRUST UNITS	56
SIGNIFICANT ACQUISITIONS	24	ADDITIONAL INFORMATION	56
CORPORATE STRATEGY AND RISK
MANAGEMENT	25
General	25
Risk Management	25
SCHEDULE A - AUDIT COMMITTEE INFORMATION

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GLOSSARY OF TERMS

"8% Debentures" means the 8% convertible unsecured subordinated debentures of the Trust;

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

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

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

"Accrete" means Accrete Energy Inc., formerly 1101130 Alberta Ltd.;

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

"affiliate" or "associate" when used to indicate a relationship with a person or company, means the same as set forth in the Securities Act (Alberta);

"AMEX" means the American Stock Exchange;

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

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

"Breitburn L.P." means Breitburn Energy Company L.P., a Delaware limited partnership and an indirect subsidiary of the Trust;

"Breitburn" means Breitburn Energy Company LLC, a former California limited liability company;

"Breitburn Acquisition" means the transaction in which the Trust acquired all of the issued and outstanding shares of Breitburn pursuant to an agreement and plan of merger dated June 15, 2004 among the Trust, Breitburn, Pro GP Corp., Pro LP Corp. and BB Merger LLC;

"Breitburn Properties" means the oil and gas properties held by Breitburn L.P. in the State of California with minor interests offshore in the Gulf of Mexico and the State of Wyoming;

"CGA" means Cawley, Gillespie and Associates, Inc., independent petroleum engineers;

"Chamaelo" means Chamaelo Energy Inc., formerly 1100974 Alberta Inc.;

"Distributable Cash" means all amounts distributed or to be distributed during any applicable period to Unitholders;

"Distribution Record Date" means on or about the 20^th day of each calendar month or such other date as may be determined from time to time by the Trustee;

"Founders" means Founders Energy Ltd., a predecessor of Provident;

"GLJ" means Gilbert Laustsen Jung Associates Ltd., independent petroleum engineers;

"Holdings Trust" means Provident Holdings Trust;

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"Initial 6.5% Debentures" means the 6.5% convertible unsecured subordinated debentures of the Trust issued on March 1, 2005;

"Kinetic" means collectively, Kinetic Resources U.S.A., a partnership formed under the laws of the State of Michigan and Kinetic Resources (LPG), a partnership formed under the laws of the Province of Alberta;

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

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

"Meota" means Meota Resources Corp.;

"Midstream NGL Acquisition" means the acquisition by Provident of certain assets, shares and partnership interests which comprised the natural gas liquids business of EnCana Corporation, 1140102 Alberta Ltd., EnCana Midstream Inc., WD Energy Services Inc. and EnCana Kerrobert Pipelines Limited for an aggregate purchase price of $697 million, plus working capital and other adjustments which closed on December 13, 2005;

"Midstream NGL Business"means the natural gas midstream, NGL processing and marketing business acquired by Provident from EnCana Corporation, 1140102 Alberta Ltd., EnCana Midstream Inc., WD Energy Services Inc. and EnCana Kerrobert Pipelines Limited;

"NSA" means Netherland, Sewell and Associates, Inc., independent petroleum engineers;

"Nautilus" means Nautilus Resources LLC;

"Nautilus Acquisition" means the acquisition of all of the membership interests in Nautilus by Breitburn L.P. pursuant to a membership interest purchase and sale agreement dated February 9, 2005 among Breitburn L.P. and all of the membership interest holders of Nautilus;

"Nautilus Properties" means the oil and gas producing properties in the State of Wyoming held by Nautilus and acquired by Breitburn L.P. pursuant to the Nautilus Acquisition;

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

"NYSE" means the New York Stock Exchange;

"Olympia" means Olympia Energy Inc.;

"Olympia Arrangement" means the plan of arrangement in which the Trust acquired all of the issued and outstanding common shares of Olympia pursuant to an arrangement agreement dated April 6, 2004 among the Trust, Provident, Olympia and Accrete;

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

"Orcutt Hill Acquisition" means the acquisition by Breitburn L.P. of certain oil and natural gas producing properties, related interests and 5,000 acres of surface acreage situated in the Orcutt Hill Oil Field located in Santa Barbara County, California pursuant to a purchase and sale agreement dated September 13, 2004 between Breitburn L.P. and an arm's length third party vendor;

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"Orcutt Hill Properties" means the oil and natural gas producing properties, related interests and 5,000 acres of surface acreage situated in the Orcutt Hill Oil Field located in Santa Barbara County, California acquired by Breitburn L.P. pursuant to the Orcutt Hill Acquisition;

"PAI" means Provident Acquisitions Inc.;

"Permitted Investments" means: (i) obligations issued or guaranteed by the government of Canada or any province of Canada or any agency or instrumentality thereof; (ii) term deposits, guaranteed investment certificates, certificates of deposit or bankers' acceptances of or guaranteed by any Canadian chartered bank or other financial institutions (including the Trustee and any affiliate of the Trustee) the short-term debt or deposits of which have been rated at least A or the equivalent by Standard & Poor's Corporation, Moody's Investors Service, Inc., Canadian Bond Rating Service Inc. or Dominion Bond Rating Service Limited; and (iii) commercial paper rated at least A or the equivalent by Canadian Bond Rating Service Inc. or Dominion Bond Rating Service Limited, in each case maturing within 180 days after the date of acquisition;

"PMI" means Provident Midstream Inc.;

"PHC" means Pro Holding Company;

"Provident" means Provident Energy Ltd.;

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

"Redwater Midstream NGL Assets" means the assets acquired pursuant to the Redwater Acquisition consisting of a natural gas gathering system and processing plant, as well as an NGL extraction plant, fractionation facilities, transportation systems and storage assets previously owned by Williams Canada;

"Special Resolution" means a resolution proposed to be passed as a special resolution at a meeting of Unitholders (including an adjourned meeting) duly convened for the purpose and held in accordance with the provisions of the Trust Indenture at which two or more holders of at least 5% of the aggregate number of Trust Units then outstanding are present in person or by proxy and passed by the affirmative votes of the holders of not less than 66 2/3% of the Trust Units represented at the meeting and voted on a poll upon such resolution;

"Special Voting Unit" means a special voting unit of the Trust, which shall be entitled to such number of votes at meetings of Unitholders equal to such number of votes and any other rights or limitations to be prescribed by the board of directors of Provident in the resolution issuing any such Special Voting Units;

"Subsequent Investment" means those investments which the Trust is permitted to make pursuant to the Trust Indenture, namely royalties in respect of Provident's oil and gas properties and securities of Provident or any other subsidiary of the Trust to fund the acquisition, development, exploitation and disposition of all types of petroleum and natural gas and energy related assets, including without limitation, facilities of any kind, oil sands interests, electricity or power generating assets, and pipeline, gathering, processing and transportation assets and whether effected through an acquisition of assets or an acquisition of shares or other form of ownership interest in any entity the substantial majority of the assets of which are comprised of like assets;

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"Subsidiary" means, when used to indicate a relationship with another body corporate:

(a) a body corporate which is controlled by (i) that other, or (ii) that other and one or more bodies corporate, each of which is controlled by that other, or (iii) two or more bodies corporate each of which is controlled by that other, or

(b)a subsidiary of a body corporate that is the other's subsidiary;

and in the case of the Trust, includes Provident;

"Supplemental 6.5% Debentures" means the 6.5% convertible unsecured subordinated debentures of the Trust issued on November 15, 2005;

"Tax Act" means the Income Tax Act (Canada), R.S.C. 1985, c.1, 5th Supplement, as amended;

"Trust" means Provident Energy Trust, a trust settled pursuant to the laws of Alberta;

"Trust Indenture" means the trust indenture dated as of January 25, 2001 as amended from time to time, between Computershare Trust Company of Canada and Founders;

"Trust Fund", at any time, shall mean such of the following monies, properties and assets that are at such time held by the Trustee for the purposes of the Trust under the Trust Indenture: (a) the initial $100 used to settle the Trust; (b) all funds realized from the issuance of Trust Units; (c) any Permitted Investments in which funds may from time to time be invested; (d) the initial royalty granted to the Trust; (e) any Subsequent Investment; (f) any proceeds of disposition of any of the foregoing property; (g) the common shares of Founders and the initial notes of Provident held by the Trust; and (h) all income, interest, profit, gains and accretions and additional assets, rights and benefits of any kind or nature whatsoever arising directly or indirectly from or in connection with or accruing to such foregoing property or such proceeds of disposition;

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

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

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

"TSX" means the Toronto Stock Exchange;

"United States" and "U.S." mean the United States of America, it territories and possessions, any state of the United States, and the District of Columbia;

"Viracocha" means Viracocha Energy Inc.;

"Viracocha Arrangement" means the plan of arrangement in which the Trust acquired all of the issued and outstanding common shares of Viracocha pursuant to an arrangement agreement dated April 6, 2004 among the Trust, Provident, Viracocha and Chamaelo; and

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

Words importing the singular number only include the plural and vice versa and words importing any gender include all genders. All dollar amounts set forth in this Annual Information Form are in Canadian dollars, except where otherwise indicated.

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ABBREVIATIONS, TERMS AND CONVERSIONS

In this Annual Information Form, the abbreviations and terms set forth below have the meanings indicated.

Oil and Natural Gas Liquids		Natural Gas
bbls	barrels	Mcf	thousand cubic feet
Mbbl	thousand barrels	MMcf	million cubic feet
bpd or bbl/d	barrels of oil per day	bcf	billion cubic feet
mmbbls	million barrels	mcfd or Mcf/d	thousand cubic feet per day
NGLs	natural gas liquids	mmcfd	million cubic feet per day
STB	stock tank barrel of oil	m3	cubic metres
Mstb	thousand stock tank barrels of oil	mmbtu	million British Thermal Units
boed or boe/d	barrels of oil equivalent per day	GJ	gigajoule
		gjpd	gigajoule per day
Other
boe	means barrel of oil equivalent, using the conversion factor of 6 mcf of natural gas being equivalent to one bbl of oil, unless otherwise specified. The conversion factor used to convert natural gas to oil equivalent is not necessarily based upon either energy or price equivalents at this time.
mboe	means thousand barrels of oil equivalent.
mmboe	means million barrels of oil equivalent.
WTI	means West Texas Intermediate.
API	means the measure of the density or gravity of liquid petroleum products derived from a specific gravity.

The following table sets forth certain conversions between Standard Imperial Units and the International System of Units (or metric units).

To Convert From	To	Multiply By
mcf	cubic metres	0.0282
cubic metres	cubic feet	35.494
Bbls	cubic metres	0.159
cubic metres	bbls	6.289
feet	metres	0.305
metres	feet	3.281
miles	kilometres	1.609
kilometres	miles	0.621
acres	hectares	0.405
hectares	acres	2.471
gigajoules	mmbtu	0.950

PRESENTATION OF OIL AND GAS RESERVES AND PRODUCTION INFORMATION

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

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NON-GAAP MEASURES

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

NOTE REGARDING FORWARD LOOKING STATEMENTS

This Annual Information Form and the documents incorporated by reference herein contain forward-looking statements. These statements relate to future events or the Trust's future performance. All statements other than statements of historical fact are forward-looking statements. In some cases, forward-looking statements can be identified by terminology such as "may", "will", "should", "expect", "plan", "anticipate", "believe", "estimate", "predict", "potential", "continue", or the negative of these terms or other comparable terminology. Forward looking statements or information in this analysis include, but are not limited to, business strategy and objectives, reserve quantities and the discounted present value of future net cash flows from such reserves, net revenue, future production levels, capital expenditures, exploration plans, development plans, acquisition and disposition plans and the timing thereof, operating and other costs, royalty rates, budgeted levels of cash distributions and the performance associated with Provident's natural gas midstream, NGL processing and marketing business. These statements are only predictions. Actual events or results may differ materially. In addition, this Annual Information Form and the documents incorporated by reference herein may contain forward-looking statements attributed to third party industry sources. Undue reliance should not be placed on these forward-looking statements, as there can be no assurance that the plans, intentions or expectations upon which they are based will occur. By its nature, forward-looking information involves numerous assumptions, known and unknown risks and uncertainties, both general and specific, that contribute to the possibility that the predictions, forecasts, projections and other forward-looking statements will not occur. Forward-looking statements in this Annual Information Form and the documents incorporated by reference herein include, but are not limited to, statements with respect to:

· the Trust's ability to benefit from the combination of growth opportunities and the ability to grow through the capital markets;

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

· sustainability and growth of production and reserves through prudent management and acquisitions;

· the emergence of accretive growth opportunities;

· the ability to achieve a consistent level of monthly cash distributions;

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· the impact of Canadian governmental regulation on the Trust;

· the existence, operation and strategy of the commodity price risk management program;

· the approximate and maximum amount of forward sales and hedging to be employed;

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

· the level of capital expenditures devoted to development activity rather than exploration;

· the sale, farming out or development using third party resources to exploit or produce certain exploration properties;

· the use of development activity and acquisitions to replace and add to reserves;

· the quantity of oil and natural gas reserves and oil and natural gas production levels;

· currency, exchange and interest rates;

· the performance characteristics of Provident's natural gas midstream, NGL processing and marketing business;

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

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

Although the Trust believes that the expectations reflected in the forward-looking statements are reasonable, there can be no assurance that such expectations will prove to be correct. The Trust can not guarantee future results, levels of activity, performance, or achievements. Moreover, neither the Trust nor any other person assumes responsibility for the accuracy and completeness of the forward-looking statements. Some of the risks and other factors, some of which are beyond the Trust's control, which could cause results to differ materially from those expressed in the forward-looking statements contained in this Annual Information Form and the documents incorporated by reference herein include, but are not limited to:

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

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

· uncertainties associated with estimating reserves;

· royalties payable in respect of oil and gas production;

· governmental regulation of the oil and gas industry, including income tax and environmental regulation;

· fluctuation in foreign exchange or interest rates;

· stock market volatility and market valuations;

· the impact of environmental events;

· the need to obtain required approvals from regulatory authorities;

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

· failure to obtain industry partner and other third party consents and approvals, when required;

· third party performance of obligations under contractual arrangements; and

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

Statements relating to "reserves" or "resources" are deemed to be forward-looking statements, as they involve the implied assessment, based on certain estimates and assumptions, that the resources and reserves described can be profitably produced in the future. Readers are cautioned that the foregoing list of factors is not exhaustive. The forward-looking statements contained in this Annual Information Form and the documents incorporated by reference herein are expressly qualified by this cautionary statement. Subject to the Trust's obligations under applicable securities laws, the Trust is not under any duty to update any of the forward-looking statements after the date of this Annual Information Form to conform such statements to actual results or to changes in the Trust's expectations.

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INCORPORATION AND STRUCTURE

The Trust

Provident Energy Trust is an open-end unincorporated investment trust governed by the laws of the Province of Alberta and created pursuant to the Trust Indenture. The head and principal offices of the Trust are located at 800, 112 - 4th Avenue S.W., Calgary, Alberta T2P 0H3. The registered office of the Trust is located at 3700, 400 - 3rd Avenue S.W., Calgary, Alberta T2P 4H2.

Provident

Provident Energy Ltd. is a corporation the common shares of which are wholly-owned by the Trust. Provident was incorporated under the ABCA on January 19, 2001 and was amalgamated with Founders pursuant to a plan of arrangement involving the Trust, Provident and Founders effective March 6, 2001. Provident subsequently amalgamated with Maxx Petroleum Ltd. ("Maxx") effective May 25, 2001 pursuant to a plan of arrangement involving the Trust, Provident and Maxx. Provident was also amalgamated with Richland Petroleum Corporation ("Richland") effective January 16, 2002 pursuant to a plan of arrangement involving the Trust, Provident and Richland. Provident was amalgamated with Provident Management Corporation pursuant to a management internalization transaction involving the Trust, Provident, the Manager and the shareholders of the Manager effective January 17, 2003. Provident was also amalgamated with Olympia and Viracocha on June 1, 2004 pursuant to plans of arrangement involving the Trust, Provident, Viracocha and Olympia. The head and principal offices of Provident are located at 800, 112 - 4th Avenue S.W., Calgary, Alberta T2P 0H3. The registered office of Provident is located at 3700, 400 - 3rd Avenue S.W., Calgary, Alberta T2P 4H2.

Provident Holdings Trust

Provident Holdings Trust is an open-end unincorporated commercial trust governed by the laws of the Province of Alberta. Holdings Trust was formed pursuant to a trust indenture dated April 25, 2002 and is wholly-owned by the Trust. Holdings Trust currently holds a 99% limited partnership interest in the limited partnerships, Provident Acquisitions L.P., Provident Marketing L.P. and Provident Midstream L.P. The head and principal offices of Holdings Trust are located at 800, 112 - 4th Avenue S.W., Calgary, Alberta T2P 0H3. The registered office of Holdings Trust is located at 3700, 400 - 3rd Avenue S.W., Calgary, Alberta T2P 4H2.

Provident Acquisitions L.P.

Provident Acquisitions L.P. is a limited partnership registered in the Province of Alberta. Provident Acquisitions L.P. was formed pursuant to a limited partnership agreement dated April 19, 2002. The general partner of Provident Acquisitions L.P. is Provident which holds a 1% interest in the partnership. Holdings Trust is the limited partner of Provident Acquisitions L.P. with a 99% interest in the partnership. The head and principal offices of Provident Acquisitions L.P. are located at 800, 112 - 4th Avenue S.W., Calgary, Alberta T2P 0H3. The registered office of Provident Acquisitions L.P. is located at 3700, 400 - 3rd Avenue S.W., Calgary, Alberta T2P 4H2.

Provident Midstream L.P.

Provident Midstream L.P. is a limited partnership registered in the Province of Alberta. Provident Midstream L.P. was formed pursuant to a limited partnership agreement dated December 8, 2005. Provident Midstream L.P. directly and indirectly holds the Canadian partnership interests acquired pursuant to the Midstream NGL Acquisition. The general partner of Provident Midstream L.P. is

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Provident GP Inc. which holds a 1% interest in the partnership. Holdings Trust and PMI are the limited partners of Provident Midstream L.P. with a 99% total interest in the partnership. The head and principal offices of Provident Midstream L.P. are located at 800, 112 - 4th Avenue S.W., Calgary, Alberta T2P 0H3. The registered office of Provident Midstream L.P. is located at 3700, 400 - 3rd Avenue S.W., Calgary, Alberta T2P 4H2.

Provident Acquisitions Inc.

Provident Acquisitions Inc. is a corporation wholly-owned by Provident. PAI was incorporated under the ABCA on August 19, 2002. PAI is the beneficial owner of all of the Class A common shares of 101011500 Saskatchewan Ltd. ("Provident Saskco") and holds a 0.00001% interest in the Meota (2000) Partnership. Provident Saskco holds the remaining interest in the Meota (2000) Partnership. The head and principal offices of PAI are located at 800, 112 - 4th Avenue S.W., Calgary, Alberta T2P 0H3. The registered office of PAI is located at 3700, 400 - 3rd Avenue S.W., Calgary, Alberta T2P 4H2.

Provident Midstream Inc.

Provident Midstream Inc. is a corporation wholly-owned by Provident and Pro Holding Company. PMI was incorporated under the ABCA on June 6, 2005. PMI holds Provident's Redwater Midstream NGL Assets. The head and principal offices of PMI are located at 800, 112 - 4th Avenue S.W., Calgary, Alberta T2P 0H3. The registered office of PMI is located at 3700, 400 - 3rd Avenue S.W., Calgary, Alberta T2P 4H3.

Pro Holding Company

Pro Holding Company is a corporation incorporated under the laws of Delaware and is wholly-owned by the Trust and Provident. PHC owns all of the outstanding shares of Pro LP Corp. and Pro GP Corp. which in turn own approximately 96% of the outstanding partnership interests in Breitburn L.P. PHC also owns all of the shares of Pro US LLC and Pro Midstream Company which are the partners of the Kinetic Resources U.S.A. partnership. The head and principal offices of PHC are located at 515 S. Flower Street, Suite 4800, Los Angeles, California. The registered office of PHC is located at 2711 Centerville Road, Suite 400, Wilmington, Delaware.

Breitburn Energy Company L.P.

Breitburn Energy Company L.P. is a Delaware limited partnership and an indirect subsidiary of the Trust. Breitburn L.P. resulted from the merger of Breitburn, a former California limited liability company, and BB Merger LLC, a Delaware limited liability company and wholly-owned indirect subsidiary of the Trust, upon completion of the indirect acquisition of all of the issued and outstanding shares of Breitburn by the Trust on June 15, 2004. The Trust, through Pro Holding Company, Pro LP Corp. and Pro GP Corp., currently holds approximately 96% of the outstanding partnership interests in Breitburn L.P. with the remaining partnership interests held by Breitburn's co-founders and co-chief executive officers. The head and principal offices of Breitburn L.P. are located at 515 S. Flower Street, Suite 4800, Los Angeles, California. The registered office of Breitburn L.P. is 2711 Centerville Road, Suite 400, Wilmington, Delaware.

INTERCORPORATE RELATIONSHIPS

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

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INFORMATION CONCERNING THE TRUST, PROVIDENT AND CERTAIN SUBSIDIARIES

Provident Energy Trust

Cash Flow

The Trust indirectly holds interests in petroleum and natural gas properties and the natural gas midstream, NGL processing and marketing business through Provident and its various subsidiaries. Cash flow from the petroleum and natural gas properties flows from Provident and the Trust's various subsidiaries to the Trust by way of royalty payments and interest payments and principal repayments on notes issued by the Trust from time to time. Cash flow from the natural gas midstream, NGL processing and marketing business flows from Provident to the Trust and the Trust's various subsidiaries by way of interest payments and principal repayments on notes issued by the Trust. Distributable income generated by the royalty payments, interest payments and principal repayments is then distributed monthly to the Unitholders.

Under the terms of the Trust Indenture the Trust is also entitled to (i) invest in securities of Provident from time to time; (ii) acquire royalties; (iii) temporarily hold cash and Permitted Investments for the purposes of paying the expenses and liabilities of the Trust and paying amounts payable by the Trust in connection with the redemption of any Trust Units and making distributions to Unitholders; (iv) acquire or invest in Subsequent Investments; and (v) pay the costs, fees and expenses associated with or incidental to the foregoing.

Cash Distributions

The Trustee intends to make cash distributions on or about the 15th day of each month to Unitholders of record on the immediately preceding Distribution Record Date in amounts equal to all of the interest, royalty and dividend income of the Trust, net of the Trust's administrative expenses. In addition, Unitholders may, at the discretion of the Trustee, receive distributions in respect of repayments of principal made by Provident to the Trust on notes issued by the Trust from time to time. It is anticipated however, that the Trust will reinvest a portion of the repayments of principal on the notes outstanding to enable Provident to make capital expenditures to develop or acquire additional oil and natural gas properties to enhance cash flow from operations.

The Trust seeks to provide a stable stream of cash distributions, subject to, among other things, fluctuations in the quantity of petroleum and natural gas substances produced, prices received for that production, hedging contract receipts and payments, taxes, direct expenses of the Trust, reclamation fund contributions, fluctuations in the demand for NGLs and natural gas, competition from other gas processing plants, operational matters and hazards related to the natural gas midstream, NGL processing and marketing business, capital expenditures, debt servicing, operating costs, debt service charges and general and administrative expenses as determined necessary by Provident on behalf of the Trust.

Trust Units

An unlimited number of Trust Units may be created and issued pursuant to the Trust Indenture. Each Trust Unit represents an equal fractional undivided beneficial interest in any distribution from the Trust (whether of net income, net realized capital gains or other amounts) and in any net assets of the Trust in the event of termination or winding-up of the Trust. All Trust Units outstanding from time to time shall be entitled to an equal share of any distributions from, and in any net assets of, the Trust in the event of the termination or winding-up of the Trust. All Trust Units rank among themselves equally and rateably without discrimination, preference or priority. Each Trust Unit is transferable, is not subject to any conversion or pre-emptive rights and entitles the holder thereof to require the Trust to redeem any or all of the Trust Units held by such holder and to one vote at all meetings of holders of Trust Units for each Trust Unit held. Holders of Trust Units shall not be subject to any liability in contract or tort or of any other kind in connection with the assets, obligations or affairs of the Trust or with respect to any acts performed by the Trustee or any other person pursuant to the Trust Indenture.

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Special Voting Units

An unlimited number of Special Voting Units may be created and issued pursuant to the Trust Indenture. Holders of Special Voting Units shall not be entitled to any distributions of any nature whatsoever from Provident and shall be entitled to such number of votes at meetings of holders of Trust Units as may be prescribed by the board of directors of Provident in the resolution authorizing the issuance of any Special Voting Units. Except for the right to vote at meetings of the holders of Trust Units, the Special Voting Units shall not confer upon the holders thereof any other rights. As of March 21, 2006, there was one Special Voting Unit issued and outstanding.

8.75% Debentures

In September 2003, the Trust issued $75,000,000 aggregate principal amount of convertible unsecured subordinated debentures. The 8.75% Debentures mature on December 31, 2008 and bear interest at a rate of 8.75% per annum, payable semi-annually in arrears on June 30 and December 31 in each year. The 8.75% Debentures are convertible at the option of the holder into Trust Units at any time prior to the earlier of December 31, 2008 and the business day immediately preceding any date specified by the Trust for redemption at a conversion price of $11.05 per Trust Unit, subject to adjustment in certain circumstances. After January 1, 2007 and prior to maturity, the Trust may redeem the 8.75% Debentures in whole or in part from time to time at a price of $1,050 per 8.75% Debenture from January 1, 2007 until January 1, 2008 and at a price of $1,025 per 8.75% Debenture thereafter until maturity, in each case plus accrued and unpaid interest. On redemption or maturity of the 8.75% Debentures, the Trust may, subject to regulatory approval, elect to satisfy the redemption price or principal amount by issuing Trust Units to the 8.75% Debenture holder. As of March 21, 2006, there was $32,254,000 aggregate principal amount of 8.75% Debentures outstanding.

8% Debentures

In July 2004, the Trust issued $50,000,000 aggregate principal amount of convertible unsecured subordinated debentures. The 8% Debentures mature on July 31, 2009 and bear interest at a rate of 8% per annum, payable semi-annually in arrears on July 31 and January 31 in each year. The 8% Debentures are convertible at the option of the holder into Trust Units at any time prior to the earlier of July 31, 2009 and the business day immediately preceding any date specified by the Trust for redemption at a conversion price of $12.00 per Trust Unit, subject to adjustment in certain circumstances. After July 31, 2007 and prior to maturity, the Trust may redeem the 8% Debentures in whole or in part from time to time at a price of $1,050 per 8% Debenture from July 31, 2007 until July 31, 2008 and at a price of $1,025 per 8% Debenture thereafter until maturity, in each case plus accrued and unpaid interest. On redemption or maturity of the 8% Debentures, the Trust may, subject to regulatory approval, elect to satisfy the redemption price or principal amount by issuing Trust Units to the 8% Debenture holder. As of March 21, 2006, there was $33,578,000 aggregate principal amount of 8% Debentures outstanding.

Initial 6.5% Debentures

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

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2009 and on or before August 31, 2010 and after August 31, 2010 and prior to maturity at a price of $1,000 per Initial 6.5% Debenture, in each case plus accrued and unpaid interest. On redemption or maturity of the Initial 6.5% Debentures, the Trust may, subject to regulatory approval, elect to satisfy the redemption price or principal amount by issuing Trust Units to the Initial 6.5% Debenture holder. As of March 21, 2006, there was $99,034,000 aggregate principal amount of Initial 6.5% Debentures outstanding.

Supplemental 6.5% Debentures

In November 2005, the Trust issued $150,000,000 aggregate principal amount of convertible unsecured subordinated debentures. The Supplemental 6.5% Debentures mature on April 30, 2011 and bear interest at a rate of 6.5% per annum, payable semi-annually in arrears on April 30 and October 31 in each year, commencing April 30, 2006. The Supplemental 6.5% Debentures are convertible at the option of the holder into Trust Units at any time prior to the earlier of April 30, 2011 and the business day immediately preceding any date specified by the Trust for redemption at a conversion price of $14.75 per Trust Unit, subject to adjustment in certain circumstances. After October 31, 2008 and prior to maturity, the Trust may redeem the Supplemental 6.5% Debentures in whole or in part from time to time at a price of $1,050 per 6.5% Debenture from October 31, 2008 until October 31, 2009, at a price of $1,025 per Supplemental 6.5% Debenture after October 31, 2009 and on or before October 31, 2011, in each case plus accrued and unpaid interest. On redemption or maturity of the Supplemental 6.5% Debentures, the Trust may, subject to regulatory approval, elect to satisfy the redemption price or principal amount by issuing Trust Units to the Supplemental 6.5% Debenture holder. As of March 21, 2006, there was $150,000,000 aggregate principal amount of Supplemental 6.5% Debentures outstanding.

Meetings of Unitholders

Meetings of holders of Trust Units will be called and held annually for, among other things, the election of the directors of Provident and the appointment of the auditors of the Trust. The Trust Indenture provides that meetings of Unitholders must be called and held for, among other matters, the election or removal of the Trustee, the appointment or removal of the auditors of the Trust, the approval of certain amendments to the Trust Indenture, to assign, transfer or dispose of royalties as an entirety or substantially as an entirety, and the commencement of winding-up the affairs of the Trust.

Unitholders may attend and vote at all meetings of Unitholders either in person or by proxy and a proxy holder need not be a holder of Trust Units. Two persons present in person or represented by proxy and representing in the aggregate at least 5% of the votes attaching to all outstanding Trust Units shall constitute a quorum for the transaction of business at all such meetings. For the purposes of determining such quorum, the holders of any issued Special Voting Units who are present at the meeting shall be regarded as representing outstanding Trust Units equivalent in number to the votes attaching to such Special Voting Units.

Termination of the Trust

Unitholders may vote to terminate the Trust at any meeting of Unitholders duly called for that purpose, subject to the following: (a) a vote may only be held if requested in writing by the holders of not less than 20% of the Trust Units; (b) a quorum of 50% of the issued and outstanding Trust Units is present in person or by proxy; and (c) the termination must be approved by Special Resolution.

Unless the Trust is terminated or extended by vote of Unitholders earlier, the Trustee shall commence to wind-up the affairs of the Trust on December 31, 2099. In the event that the Trust is wound-up, the Trustee will sell and convert into money certain royalties and other assets in one transaction or in a series of transactions at public or private sale and do all other acts as may be appropriate to liquidate assets and shall in all respects act in accordance with the directions, if any, of the Unitholders in respect of the Special Resolution authorizing the termination of the Trust. After paying, retiring or discharging or making provision for the payment, retirement or discharge of all known liabilities and obligations of the

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Trust and providing for indemnity against any other outstanding liabilities and obligations, the Trustee shall distribute the remaining part of the proceeds of the sale of the assets together with any cash remaining in the Trust among the Unitholders in accordance with their pro rata share.

Trust Unit Option Plan

The Trust discontinued its trust unit option plan as of May 2, 2005. No options were issued under the Option Plan after March 2005 and the Trust does not intend to issue any further options under the Option Plan in the future. However, options to acquire Trust Units previously granted under the Option Plan will continue to remain exercisable in accordance with their terms. Additional information concerning the Option Plan is included in the Trust's Proxy Statement and Information Circular dated March 31, 2006. As of March 21, 2006, there were 3,081,837 options granted and outstanding under the Option Plan.

Premium Distribution, Distribution Reinvestment and Optional Unit Purchase Plan

The Trust has implemented a premium distribution, distribution reinvestment and optional unit purchase plan (the "DRIP") to provide holders of Trust Units with a means to automatically reinvest sums received on account of distributions on Trust Units. Provident reserves the right to prorate the participation in the DRIP to manage the amount of cash reinvested in the Trust and the Trust Units issued under the DRIP. Computershare Trust Company of Canada, as plan agent, may at the election of a participant (a) purchase Trust Units with the cash distributions at 95% of the market value of the Trust Units, or (b) elect to purchase additional Trust Units with the cash distributions and deliver such Trust Units to a broker in exchange for a premium cash distribution equal to an amount up to 102% of the monthly cash distribution, or (c) purchase new Trust Units under the optional unit purchase plan at a subscription price of 100% of the average market price of the Trust Units. If a participant has elected either (a) or (b), the plan agent may, on behalf of such participant, purchase additional Trust Units with the cash distributions at the market value of such Trust Units. Residents of Canada are eligible to elect options (a), (b), or (c). Due to regulatory restrictions, residents of the United States are eligible to elect option (a) only at this time.

Limitation on Non-Resident Trust Unitholders

In accordance with the Trust Indenture, in order to ensure the maintenance of the Trust's "mutual fund trust" status, Provident will: (i) prior to the consummation of any transaction involving the acquisition by the Trust of any Subsequent Investment; (ii) prior to any material modification to the Trust Fund other than as contemplated by subclause (i); (iii) promptly following any proposed amendment to paragraph 132(7)(a) of the Tax Act (which provision relates to the level of "taxable Canadian property") or the publication of any administrative bulletin or other notice of interpretation relating to the interpretation or application of such section; or (iv) otherwise at any time when requested by the Trustee, obtain an opinion of counsel confirming whether the Trust is, at the date thereof and following such transaction or event (which in the case of (iii) shall mean the coming into effect of the amendment or change of interpretation), entitled to rely on paragraph 132(7)(a) of the Tax Act (or any successor provision thereto) for purposes of qualifying as a "mutual fund trust" under the Tax Act.

If at any time the board of directors of Provident determines, in its sole discretion, or becomes aware that the Trust's ability to continue to rely on paragraph 132(7)(a) of the Tax Act (or any successor provision thereto) for purposes of qualifying as a "mutual fund trust" thereunder is in jeopardy, then forthwith after such determination Provident will take such steps as are necessary or desirable to ensure that the Trust is not maintained primarily for the benefit of Non-Residents.

Provident may, at any time and from time to time, in its sole discretion, request that the Trustee make reasonable efforts, as practicable in the circumstances, to obtain declarations as to beneficial ownership, perform residency searches of shareholder and beneficial shareholder mailing address lists and take such other steps specified by Provident, at the cost of the Trust, to determine or estimate as best possible the residence of the beneficial owners of Trust Units.

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If at any time the board of directors of Provident, in its sole discretion, determines that it is in the best interest of the Trust, Provident, notwithstanding the ability of the Trust to continue to rely on subsection 132(7)(a) of the Tax Act for the purpose of qualifying as a "mutual fund trust" under the Tax Act, may (i) require the Trustee to refuse to accept a subscription for Trust Units from, or issue or register a transfer of Trust Units to, a person unless the person provides a declaration to Provident that the Trust Units to be issued or transferred to such person will not when issued or transferred be beneficially owned by a Non-Resident; (ii) to the extent practicable in the circumstances, send a notice to registered holders of Trust Units which are beneficially owned by Non-Residents, chosen in inverse order to the order of acquisition or registration of such Trust Units beneficially owned by Non-Residents or in such other manner as Provident may consider equitable and practicable, requiring them to sell their Trust Units which are beneficially owned by Non-Residents or a specified portion thereof within a specified period of not less than 60 days. If the Unitholders receiving such notice have not sold the specified number of such Trust Units or provided Provident with satisfactory evidence that such Trust Units are not beneficially owned by Non-Residents within such period, Provident may, on behalf of such registered Unitholder, sell such Trust Units and, in the interim, suspend the voting and distribution rights attached to such Trust Units and make any distribution in respect of such Trust Units by depositing such amount in a separate bank account in a Canadian chartered bank (net of any applicable taxes). Any sale shall be made on any stock exchange on which the Trust Units are then listed and, upon such sale, the affected holders shall cease to be holders of Trust Units so disposed of and their rights shall be limited to receiving the net proceeds of sale, and any distribution in respect thereof deposited as aforesaid, net of applicable taxes and costs of sale, upon surrender of the certificates representing such Trust Units; (iii) delist the Trust Units from any non-Canadian stock exchange; and (iv) take such other actions as the board of directors of Provident determines, in its sole discretion, are appropriate in the circumstances that will reduce or limit the number of Trust Units held by Non-Residents to ensure that the Trust is not maintained primarily for the benefit of Non-Residents.

Generally, a trust cannot qualify as a "mutual fund trust" for the purposes of the Tax Act if it is established or is being maintained primarily for the benefit of non-residents. Although not without uncertainty, this is generally accepted to exist in most situations where Non-Resident holders own significantly in excess of 50% of the aggregate number of Trust Units issued and outstanding. However, there is currently an exception to the non-resident ownership restriction in paragraph 132(7)(a) of the Tax Act where not more than 10% of the trust's property has at any time consisted of "taxable Canadian property".

Redemption Right

Trust Units are redeemable at any time on demand by the holders thereof upon delivery to the Trust of the certificate or certificates representing such Trust Units, accompanied by a duly completed and properly executed notice requesting redemption. Upon receipt of the redemption request by the Trust, the holder thereof shall only be entitled to receive a price per Trust Unit (the "Market Redemption Price") equal to the lesser of: (i) 90% of the simple average of the closing price of the Trust Units on the principal market on which the Trust Units are quoted for trading during the 10 trading day period commencing immediately after the date on which the Trust Units are surrendered for redemption; and (ii) the closing market price on the principal market on which the Trust Units are quoted for trading on the date that the Trust Units are surrendered for redemption.

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

It is anticipated that this redemption right will not be the primary mechanism for holders of Trust Units to dispose of their Trust Units. Notes which may be distributed in specie to holders of Trust Units in

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connection with a redemption will not be listed on any stock exchange and no market is expected to develop in such notes. Notes will not be qualified investments for trusts governed by registered retirement savings plans, registered retirement income funds and deferred profit sharing plans.

Trustee

Computershare Trust Company of Canada is the trustee of the Trust. The Trustee is responsible for, among other things: (a) accepting subscriptions for Trust Units and issuing Trust Units pursuant thereto; (b) maintaining the books and records of the Trust and providing timely reports to Unitholders; and (c) paying cash distributions to Unitholders. The Trust Indenture provides that the Trustee shall exercise its powers and carry out its functions thereunder as Trustee honestly, in good faith and in the best interests of the Trust and the Unitholders and, in connection therewith, shall exercise that degree of care, diligence and skill that a reasonably prudent trustee would exercise in comparable circumstances.

The initial term of the Trustee's appointment was until the first annual meeting of Unitholders. Thereafter, the Trustee shall be reappointed or changed every year as may be determined by a majority of the votes cast at a meeting of the Unitholders. The Trustee may resign upon 60 days' notice to the Trust. The Trustee may also be removed by Special Resolution. Such resignation or removal becomes effective upon the acceptance or appointment of a successor trustee.

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

Amendments to the Trust Indenture

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

·   ensuring the Trust's continuing compliance with applicable laws or requirements of any governmental agency or authority of Canada or of any province;

·   ensuring that the Trust will satisfy the provisions of each of subsections 108(2) and 132(6) of the Tax Act as from time to time amended or replaced;

·   ensuring that such additional protection is provided for interests of Unitholders as the Trustee may consider expedient;

·   removing or curing any conflicts or inconsistencies between the provisions of the Trust Indenture or any supplemental indenture and any other agreement of the Trust or any offering document pursuant to which securities of the Trust are issued, or any applicable law or regulations of any jurisdiction, provided that in the opinion of the Trustee the rights of the Trustee and of the Unitholders are not prejudiced thereby; and

·   curing, correcting or rectifying any ambiguities, defective or inconsistent provisions, errors, mistakes or omissions, provided that in the opinion of the Trustee the rights of the Trustee and of the Unitholders are not prejudiced thereby.

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Provident Energy Ltd.

The principal business of Provident is to manage and administer the operating activities associated with the oil and gas properties and the natural gas midstream, NGL processing and marketing business. Provident is also engaged in the acquisition, exploitation, development and production of crude oil and natural gas in the Western Canadian Sedimentary Basin. Provident currently has 579 employees, consultants and contract operators at its head office location and in several field offices within the core areas of Lloydminster, west central Alberta, southern Alberta, southwest Saskatchewan, southeast Saskatchewan, California and Wyoming and the NGL midstream facilities in Redwaterand Empress, Alberta, Sarnia, Ontario, Lynchburg, Virginia and Houston, Texas.

Delegation of Authority, Administration and Trust Governance

The board of directors of Provident has generally been delegated the significant management decisions of the Trust. In particular, the Trustee has delegated to Provident responsibility for any and all matters relating to: (a) the redemption of Trust Units; (b) the acquisition of Subsequent Investments by the Trust and the negotiation of management agreements respecting Subsequent Investments; (c) any offering of securities of the Trust including: (i) the listing and maintaining of the listing on the TSX or NYSE of the Trust Units; (ii) the filing of documents or obtaining of permission from any governmental or regulatory authority or the taking of any other step under federal or provincial law to enable securities which a holder of Trust Units is entitled to receive to be properly and legally delivered and thereafter traded; (iii) ensuring compliance with all applicable laws; (iv) all matters relating to the content of any prospectus, information memorandum, private placement memorandum and similar public or private offering documents, and the certification thereof; (v) all matters concerning the terms of the sale or issuance of Trust Units or rights to Trust Units; (d) the determination of any Distribution Record Date other than the last date of each calendar month; and (e) the determination of any borrowing under the Trust Indenture. Holders of Trust Units are entitled to elect all of the members of the board of directors of Provident pursuant to the terms of the Unanimous Shareholder Agreement.

Decision Making

The board of directors of Provident supervises the management of the business and affairs of the Trust, including the business and affairs of the Trust delegated to Provident. In particular, significant operational decisions and all decisions relating to: (i) the acquisition and disposition of properties for a purchase price or proceeds in excessof an amount equal to 5% of the market capitalization ofthe Trust; (ii) the approval of annual operating and capital expenditure budgets; and (iii) establishment of credit facilities, are made by the board of directors of Provident. In addition, the Trustee has delegated certain matters to the board of directors of Provident including all decisions relating to: (i) the issuance of additional Trust Units; and (ii) the determination of the amount of Distributable Cash. Any amendment to royalties will require the approval of the board of directors of Provident on behalf of the Trust. The board of directors of Provident generally holds regularly scheduled meetings to review the business and affairs of Provident and make any necessary decisions relating thereto.

Common Shares

All of the issued and outstanding common shares of Provident are held by the Trust. Each common share of Provident entitles its holder to receive notice of and to attend all meetings of the shareholders of Provident and to one vote at such meetings. The holders of the common shares are, at the discretion of the board of directors of Provident and subject to applicable legal restrictions, entitled to receive any dividends declared by the board of directors on the common shares. All such common shares are entitled to share equally in any distribution of the assets of Provident upon the liquidation, dissolution, bankruptcy

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or winding-up of Provident or other distribution of its assets among its shareholders for the purpose of winding-up its affairs. Such participation is subject to the rights, privileges, restrictions and conditions attaching to any instruments having priority over the common shares.

No dividends have been paid on the common shares of Provident. Any decision to pay dividends on the common shares of Provident in the future will be made by the board of directors of Provident on the basis of Provident's earnings, financial requirements and other conditions existing at the time.

Series A Exchangeable Shares

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

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

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

Provident is authorized to issue an unlimited number of exchangeable shares, issuable in series. As of March 21, 2006, there were 463,545 Series A exchangeable shares of Provident outstanding at an exchange ratio of 1.55261.

Series B Exchangeable Shares

On June 1, 2004, Provident issued 2,650,000 Series B exchangeable shares as partial consideration pursuant to the Viracocha Arrangement and Olympia Arrangement. The exchange ratio for the Series B exchangeable shares was initially equal to one Trust Unit for one Series B exchangeable share and was increased on each date a distribution was paid by the Trust following the date of issuance and the date the Series B exchangeable share was exchanged, at the option of the holder, into Trust Units. On January 15, 2006, all remaining Series B exchangeable shares were acquired by the Trust in exchange for Trust Units. As a result, the Trust now holds all of the issued and outstanding Series B exchangeable shares of Provident.

Royalties

Provident has granted certain royalties to the Trust which entitle the Trust to cash distributions in respect of the production from oil and gas properties held by Provident.

Provident is entitled to make farmouts or other similar dispositions of specific interests in any part of the properties subject to the royalties, and upon the farmee or other participant earning its interest pursuant to the farmout or other disposition, these royalties shall burden only the working interest retained by or reserved to Provident.

Provident is required to establish a reserve to fund future well bore and facility abandonment and environmental and reclamation obligations and liabilities (the "Reclamation Fund"). Provident currently funds this reserve at $0.30 per barrel of oil equivalent (converting gas to oil at 6:1) (in 2004 and 2003 -

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$0.25 per barrel of oil equivalent and in 2002 and prior - $0.20 per barrel of oil equivalent converting gas to oil at 10:1) produced, less current year well bore and facility abandonment and environmental and reclamation obligations and liabilities out of production revenues and other revenues for a calendar year into the Reclamation Fund.

Notes

From time to time, Provident has issued notes to the Trust in connection with certain acquisitions and other transactions undertaken by the Trust. Cash flow from Provident's producing properties distributed from Provident to the Trust includes interest payments and principal repayments on the various notes held by the Trust. In addition, cash flow from the natural gas midstream, NGL processing and marketing business flows from Provident to the Trust by way of interest payments and principal repayments on notes issued to the Trust.

Provident Holdings Trust, Provident Acquisitions L.P., Provident Marketing L.P. and Provident Midstream L.P.

Provident Acquisitions L.P. holds certain southeast Alberta properties. Holdings Trust holds a 99% interest in Provident Midstream L.P., Provident Marketing L.P. and Provident Midstream L.P. and is managed by Provident. Holdings Trust is wholly-owned by the Trust. The general partner of Provident Acquisitions L.P. is Provident. Provident Acquisitions L.P. has granted a royalty to the Trust entitling the Trust to receive the cash flow from all present and future oil and gas properties and related tangibles owned by Provident Acquisitions L.P. after certain cost expenditures and deductions. The general partner of Provident Marketing L.P. is Provident Marketing Inc. and the general partner of Provident Midstream L.P. is Provident GP Inc. Provident Midstream L.P. holds, either directly or indirectly through partnerships, all of the assets located in Canadaacquired as a result of the Midstream NGL Acquisition, other than minor general partnership interests held by Provident GP Inc., a wholly-owned subsidiary of Provident. Cash flow from these assets flows to Holdings Trust by way of distributions on limited partnership units and from Holdings Trust to the Trust by way of interest and principal payments on notes issued by Holdings Trust to the Trust.

Provident Acquisitions Inc.

PAI holds certain Alberta and Saskatchewan properties that were acquired through the purchase of Meota. PAI is managed by Provident and has 67% interest in 10101150 Saskatchewan Ltd. and a 0.00001% interest in Meota (2000) Partnership. 10101150 Saskatchewan Ltd. holds the remaining 99.9999% interest in the Meota (2000) Partnership. PAI has granted a royalty to the Trust entitling the Trust to receive the cash flow from all present and future oil and gas properties and related tangibles owned by PAI after certain cost expenditures and deductions.

Provident Midstream Inc.

PMI holds the Redwater Midstream NGL Assets. Provident receives cash flow generated by PMI by way of interest and principal payments on debt owing from PMI to Provident.

Breitburn Energy Company L.P.

Breitburn L.P. holds the Breitburn Properties acquired pursuant to the Breitburn Acquisition and the Orcutt Hill Properties acquired pursuant to the Orcutt Hill Acquisition. Breitburn L.P. also holds all of the membership interests of Nautilus, which holds oil and gas producing properties in the State of Wyoming. The Trust currently indirectly holds approximately 96% of the outstanding partnership interests of Breitburn L.P. with the remaining approximately 4% of the partnership interests held by Breitburn's co-founders and co-chief executive officers. Cash flow from the oil and gas properties and related tangibles held by Breitburn L.P. is distributed to Breitburn L.P.'s partners, Breitburn Energy  Corporation, Pro LP Corp. and Pro GP Corp. and from Pro LP Corp. and Pro GP Corp. to the Trust in the form of dividends and interest payments on intercompany debt.

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Breitburn L.P. currently has 122 employees and continues to operate and report as a separate business unit of the Trust.

Pro Holding Company

PHC owns as of the outstanding shares of Pro LP Corp. and Pro GP Corp. which in turn own approximately96%of the outstanding partnership interests in Breitburn L.P. PHC also owns all of the shares of Pro US LLC and Pro Midstream Company which in turn hold all of the partnership interests in the Kinetic Resources U.S.A. partnership. Pro US LLC holds all of the assets located in the U.S.acquired as a result of the Midstream NGL Acquisition, other than those held by the Kinetic Resources U.S.A. partnership.

Internalization of Management

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

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

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

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

The escrow agreements also provide for the monthly release from escrow of a number of Series A exchangeable shares to account for the adjustment to the exchange ratio as a result of distributions paid on the Trust Units. The release of such Series A exchangeable shares effectively releases to the Vendors the distributions paid on the Trust Units. The number of Series A exchangeable shares to be released from escrow to account for such distributions on the Trust Units shall be determined by multiplying the number

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of Series A exchangeable shares held by a Vendor on the last day of the month in question which have not been released from escrow or are not releasable from escrow by the difference between the exchange ratio in effect on the last day of the month in question and the exchange ratio in effect on the last day of the month immediately preceding the month in question and dividing the product thereof by the exchange ratio in effect on the last day of the month in question.

In the event of a change of control of the Trust or Provident, all Series A exchangeable shares held in escrow will be released to the underlying holders. In addition, the escrow agreements provide for early release of the securities in the event of the death or disability of either Thomas Buchanan or Randall Findlay, or if either is terminated from their employment with Provident or any other subsidiary of the Trust without just cause. Securities held in escrow may be charged, pledged or encumbered, provided that the securities will remain in escrow pursuant to the terms of the escrow agreements.

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

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

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

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

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

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

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

GENERAL DEVELOPMENT OF THE BUSINESS OF THE TRUST AND PROVIDENT

In March 2001, shareholders of Founders approved the reorganization of Founders into the Trust. The following information describes the development of the business of the Trust and its material subsidiaries over the last three completed financial years.

On September 30, 2003, Provident completed the acquisition of the Redwater natural gas liquids processing business from Williams Canada for an aggregate purchase price of approximately $298.6 million (including costs associated with the acquisition), subject to certain adjustments. The Redwater Midstream NGL Assets acquired pursuant to the Redwater Acquisition consisted of a natural gas

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gathering system and processing plant, as well as an NGL extraction plant, fractionation facilities, transportation systems and storage assets owned by Williams Canada. The Redwater Midstream NGL Assets are strategically located in one of the four main NGL hubs in North America and have an approximately 25% share of NGL processing capacity in western Canada with a significant amount of its capacity contracted on a long-term fee for service or fixed margin contract basis.

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

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

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

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

On April 6, 2004, the Trust, Provident, Olympia and Accrete entered into an arrangement agreement providing for the acquisition by the Trust of all of the issued and outstanding common shares of Olympia pursuant to the Olympia Arrangement. In connection with the Olympia Arrangement, certain exploration and development properties of Olympia were transferred to Accrete, a newly created company, the shares of which were distributed to Olympia's shareholders under the Olympia Arrangement. On May 27, 2004, shareholders of Olympia approved the Olympia Arrangement. On June 1, 2004, the Trust, Provident, Olympia and Accrete completed the Olympia Arrangement. Provident and Olympia were then amalgamated and continued as Provident Energy Ltd.

On April 6, 2004, the Trust, Provident, Viracocha and Chamaelo entered into an arrangement agreement providing for the acquisition by the Trust of all of the issued and outstanding common shares of Viracocha pursuant to the Viracocha Arrangement. In connection with the Viracocha Arrangement, certain exploration and development properties of Viracocha in Alberta were transferred to Chamaelo, a newly created company, the shares of which were distributed to Viracocha's shareholders under the Viracocha Arrangement. On May 27, 2004, shareholders of Viracocha approved the Viracocha Arrangement. On June 1, 2004, the Trust, Provident, Viracocha and Chamaelo completed the Viracocha Arrangement. Provident and Viracocha were then amalgamated and continued as Provident Energy Ltd.

On June 15, 2004, the Trust entered into an agreement and plan of merger among Breitburn, a California limited liability company, Pro GP Corp., 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 ("Acquisition LLC"), a Delaware limited liability company and wholly-owned indirect subsidiary of the Trust, pursuant to which the Trust acquired all of the issued and outstanding shares of Breitburn, for an aggregate purchase price of $155 million in cash and the assumption of approximately $35 million of working capital deficiency and financial obligations of Breitburn, subject to certain adjustments. Under the terms of the Breitburn agreement, Breitburn and Acquisition LLC were merged and Breitburn was converted into Breitburn L.P., a Delaware limited partnership. The Breitburn Acquisition was completed on June 15, 2004 and resulted in the Trust indirectly holding 92% of the outstanding partnership interests of Breitburn L.P. as of that date, with the remaining 8% of the outstanding partnership interests of Breitburn L.P. retained by Breitburn's co-founders and co-chief executive officers for an aggregate purchase price of $13.7 million.

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

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

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

On February 9, 2005, Breitburn L.P., entered into a membership interest purchase and sale agreement with all of the holders of membership interests in Nautilus pursuant to which Breitburn L.P. agreed to acquire all membership interests in Nautilus for an aggregate purchase price of US$75,000,000, subject to adjustment. The Nautilus Acquisition was completed on March 2, 2005. The reserves attributable to Nautilus were evaluated in accordance with NI 51-101 by NSA, independent petroleum engineers, in a report of NSA dated February 22, 2005 and effective January 1, 2005.

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

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

On May 31, 2005, all outstanding 10.5% convertible unsecured subordinated debentures of the Trust (the "10.5% Debentures"), were redeemed at an amount of $1,050 plus all accrued and unpaid interest to May 30, 2005 per each $1,000 principal amount of 10.5% Debenture. An aggregate of $3 million was paid on redemption of the 10.5% Debentures. An aggregate of 3,507,570 Trust Units were issued upon conversion of the then outstanding 10.5% Debentures prior to the redemption of such debentures.

On June 28, 2005, the Trust announced that Mr. Dan O'Byrne was appointed to the newly created position of Executive Vice-President, Operations and Chief Operating Officer. Mr. O'Byrne is responsible for Provident's oil and gas production and its midstream operations.

On October 3, 2005, the Trust announced that Mr. Grant Billing was stepping down as Chairman of the board of directors of Provident. Mr. John Zaozirny, Q.C., was appointed to replace Mr. Billing as the Chairman of the board of directors of Provident. Provident's board believes the regular rotation of the Chairman of the board of directors and Chairs of board committees is good governance practice. Mr. Billing continues to be a director of Provident.

On October 20, 2005, the Trust signed an agreement with EnCana Oil & Gas Partnership, an affiliate of EnCana Corporation, to provide rail offloading and terminalling services for condensate to be used as a heavy oil diluent. A new condensate offloading facility is under construction at Provident's NGL fractionation plant at Redwater, Alberta. The existing Redwater plant is being expanded to offload and re-deliver an additional 35,000 barrels per day of condensate for EnCana Oil & Gas Partnership and other heavy oil producers. The expansion will also include a new multi-product truck loading facility. These

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new terminals will complement the existing pipeline connections to and from the plant and are expected to be in service in the second quarter of 2006, at a total cost of approximately $50 million. Full utilization of this facility's capacity is expected by management of Provident to increase the current western Canadian diluent supply by more than 15%.

On October 27, 2005, the Trust and Provident entered into a purchase and sale agreement with EnCana Corporation, 1140102 Alberta Ltd., EnCana Midstream Inc., WD Energy Services Inc. and EnCana Kerrobert Pipelines Limited (collectively, the "EnCana Vendors") pursuant to which Provident agreed to acquire certain assets, shares and partnership interests which comprised the EnCana Vendors' natural gas liquids business for a purchase price, net of cash acquired, of $772 million. The assets of the Midstream NGL Business include interests in certain NGL extraction plants, pipelines, storage and fractionation facilities, distribution facilities, contracts and the EnCana Vendors' interest in the NGL marketing business operated by Kinetic Resources U.S.A., a partnership formed under the laws of the State of Michigan and Kinetic Resources (LPG), a partnership formed under the laws of the Province of Alberta. The Midstream NGL Acquisition was completed on December 13, 2005.

In connection with the Midstream NGL Acquisition, the Trust completed a public offering on November 15, 2005 of 21,830,000 subscription receipts and $150,000,000 aggregate principal amount of Supplemental 6.5% Debentures for gross proceeds of approximately $425,000,000. The net proceeds of the Midstream NGL Acquisition were used to pay a portion of the purchase price in respect of the Midstream NGL Acquisition. Each subscription receipt was automatically exchanged for one Trust Unit upon closing of the Midstream NGL Acquisition.

In the fourth quarter of 2005, the Trust expanded its term credit facilities from $410.0 million at December 31, 2004. The expanded facilities are comprised of $750 million of lending capacity related to its Canadian assets and US$100 million of lending capacity related to its U.S. assets. The facilities are separate and each is provided by separate syndicates of banks.

On December 16, 2005, the Trust Units were listed on the NYSE under the symbol "PVX" and the Trust discontinued the listing of the Trust Units on the AMEX.

On January 17, 2006, the Trust announced the appointment of David I. Holm to the newly-created position of Executive Vice President, Finance and Strategy, effective February 1, 2006. Mr. Holm will be responsible for overseeing corporate functions at Provident, including finance, strategy, planning, business development, risk management, and communications. On March 28, 2006, Mr. Holm was appointed Corporate Secretary.

SIGNIFICANT ACQUISITIONS

On October 27, 2005, the Trust and Provident entered into a purchase and sale agreement with the EnCana Vendors pursuant to which Provident agreed to acquire certain assets, shares and partnership interests which comprised the EnCana Vendors' natural gas liquids business. The assets of the Midstream NGL Business include interests in certain natural gas liquids extraction plants, pipelines, storage and fractionation facilities, distribution facilities, contracts and the EnCana Vendors' interest in the NGL marketing business operated by Kinetic. The Midstream NGL Acquisition closed on December 13, 2005.

The assets of the Midstream NGL Business extend from Taylor, British Columbia to Sarnia, Ontario and Lynchburg, Virginia, U.S.A. The assets of the Midstream NGL Business include interests in certain NGL extraction plants, pipelines, storage and fractionation facilities, distribution facilities, contracts, and the Vendors' interest in Kinetic, which markets NGLs, owns a distribution terminal and leases approximately 700 rail cars. Kinetic focuses on higher value markets across Canada and the United States. Kinetic has access to long term NGL supply and transportation arrangements, which enhance its optimization, arbitrage and marketing capabilities.

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Additional information concerning the Midstream NGL Acquisition, including the annual, interim and pro forma financial statements of the Midstream NGL Business, are set forth in the business acquisition report of the Trust dated February 24, 2006 incorporated by reference herein and filed on SEDAR at www.sedar.com.

CORPORATE STRATEGY AND RISK MANAGEMENT

General

Provident's strategy is focused on achieving a consistent level of monthly cash distributions to the Unitholders. To this end, Provident pursues a balanced portfolio strategy that incorporates the integration of the oil and gas production business and the natural gas midstream, NGL processing and marketing business. This balanced portfolio extends the economic life of the Trust, assists with the stability of cash flows and provides Provident access to a broader range of opportunities across the energy value chain.

With respect to the oil and gas production business, Provident is focused on the acquisition, development, exploitation, production and marketing of crude oil and natural gas. Provident's operations are currently located in five core regions in the Western Canadian Sedimentary basin and in the States of California and Wyoming. In management's opinion, these areas generally offer low to medium risk development potential and a well developed operational infrastructure, all of which is ideally suited to a trust. Provident focuses its development activities on low risk drilling opportunities that can be used to partially offset production declines.

Provident's natural gas midstream, NGL processing and marketing business adds an additional dimension to the Trust - one with minimal on-going capital requirements and reduced exposure to commodity price risk. This provides the Trust with more stable, longer life cash flows and provides the Trust access to a broader range of growth opportunities along the energy value chain.

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

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

Risk Management

Provident's integrated risk management program is designed to protect the Unitholders, as well as Provident's employees, stakeholders, environment and reputation. This key management tool helps ensure more predictable and stable cash distributions. Provident's Risk Management Committee (the "RMC"), in conjunction with the board of directors, establishes the operational, strategic and governance risk mitigation practices and guidelines for the Trust. Members of the RMC include Provident's chief executive officer, president, chief operating officer, executive vice president strategy, finance & business development, chief financial officer, and senior executive vice president of commercial development and risk management. Provident's definition of risk is broad and so too are the policies and procedures Provident uses to identify, monitor, measure and mitigate business and market risks.

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

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In 2003, Provident broadened the scope of its risk management activities hiring additional internal expertise and implementing an integrated risk management program that cuts across business lines and commodities, and incorporates systematic programs to identify, monitor, measure and mitigate business and market risks.

Commodity Price Risk

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

The CPRMP involves a disciplined hedging strategy that utilizes derivative instruments to provide for insurance against lower commodity prices, protect against price volatility, secure bank financing, improve debt coverage and assist with more predictable and stable cash distributions. The hedging strategy protects a percentage of production against a decline in commodity prices while with some products, allowing the Trust to participate in a rising commodity price environment. It provides price stabilization and protection of inventory values and fractionation spread margin associated with the midstream services and marketing business units. As well, the CPRMP reduces foreign exchange risk due to the exposure arising from the conversion of U.S. dollars into Canadian dollars.

Provident will continue to execute the CPRMP in 2006. The derivative instruments the Trust uses include puts, calls, costless collars, participating swaps, fixed and indexed referenced pricing.

Oil and Natural Gas Hedging

Provident's oil and natural gas businesses are exposed to lower commodity prices, market and quality differentials, higher power prices and the risk of operational failure.

In the oil and gas business units, the hedging cost associated with crude oil on 2005 totaled $59.0 million ($8.36 per barrel) and $5.6 million related to natural gas ($0.19 per gj), with a combined total of $64.6 million or $5.24 per boe.

In the oil and natural gas production business, Provident consistently layers in hedging positions such that it will have 50 to 70 percent of production hedged 12 months forward and 25 to 50 percent hedged 12 to 24 months out. The decisions to enter into hedge positions and risk management strategy selection are made by senior officers of Provident who are also members of the RMC. The RMC receives input and commodity expertise from each business unit in the decision making process. Strategies are selected based on their ability to help Provident provide stable cash flow and distributions per unit rather than to simply lock in a specific price per barrel of oil or cubic foot of natural gas.

Midstream Services

The business risks faced by the NGL midstream services business include a narrowing frac spread, NGL price decline between the purchase and sale of inventory, the relationship of NGL product prices to crude oil, basis risk between pricing points, higher power and operating costs, lack of available feedstock, composition of gas and operational failure.

The commodity price risk profile of the NGL midstream services business differs from that of the oil and gas production business. While oil and gas hedging involves protecting absolute prices, midstream hedging protects the margins created through buying, processing and selling commodities. Provident has a number of long-term, fee-based and fixed margin contracts in place that reduce the effects of fluctuating natural gas feedstock and NGL prices. In addition to these long-term NGL contracts, Provident utilizes derivative instruments to further protect margins and inventory values associated with the midstream business.

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To support the cash flow stream from the Midstream NGL Business that Provident acquired late in 2005, Provident implemented a hedging program to effectively fix a portion of midstream services cash flow derived from frac spread margins. The program uses a combination of hedging products to protect a floor level of cash flow on a portion of Provident's NGL production when the oil to gas ratio is above target levels.

In 2005, the midstream segment recorded a hedging cost of $2.3 million primarily on propane and ethane price stabilization and frac-spread margin hedging activities.

Foreign Currency

Provident receives both Canadian and U.S. dollars for oil and gas and NGL sales, exposing Provident to positive or negative effects of fluctuations in the U.S./Canadian dollar exchange rate. Provident manages this exposure by matching a significant portion of expected cash costs and revenues in the same currency. Provident uses derivative instruments that include forward and swap contracts to effectively manage the U.S. cash requirements of its U.S. and Canadian business lines.

Provident's foreign exchange hedging strategy reduced the effect of the 7 percent appreciation of the Canadian dollar relative to the U.S. dollar in 2005. Provident's strategy manages the exposure it has to fluctuations in the U.S./Canadian dollar exchange rate when the underlying commodity price is based upon a U.S. index price. Provident may also use derivative products that provide for insurance against a stronger Canadian dollar, while allowing it to participate if the currency weakens relative to the U.S. dollar.

The derivative hedging contracts in place at December 31, 2005 are summarized in the following tables:

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Interest Rate Risk

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

Credit Risk

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

Insurance

Provident continually reviews its insurance requirements and policies to ensure adequate coverage of its assets. Insurance is in place for property damage, general liability, environmental impact, business interruption, directors and officers. The RMC receives reports and monitors the adequacy and appropriateness of Provident's insurance coverage.

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OIL AND NATURAL GAS OPERATIONS

Provident's Canadian reserves were evaluated by McDaniel effective December 31, 2005, in accordance with NI 51-101. Provident's United States reserves were evaluated by NSA and by CGA effective December 31, 2005 in accordance with NI 51-101. McDaniel, NSA and CGA are independent qualified reserves evaluators appointed pursuant to NI 51-101. The McDaniel evaluation report is dated February 24, 2006 with a preparation date of December 31, 2005. The NSA evaluation report is dated March 27, 2006 with a preparation date of December 31, 2005 and the CGA evaluation report is dated February 1, 2006 with a preparation date of December 31, 2005.

The Trust's Statement of Reserves Data and Other Oil and Gas Information on Form 51-101F1, the Report on Reserves Data by Independent Qualified Reserves Evaluator or Auditor on Form 51-101F2 and the Report of Management and Directors on Oil and Gas Disclosure on Form 51-101F3 all dated effective March 13, 2006 have been filed on SEDAR at www.sedar.com and are incorporated by reference in this Annual Information Form.

NATURAL GAS MIDSTREAM, NGL PROCESSING AND MARKETING OPERATIONS

General

The Canadian NGL industry involves the production, transportation and marketing of products that are extracted from natural gas prior to its sale to end use customers. On a production basis, the Canadian industry is about one third the size of the US industry, and Provident's natural gas midstream, NGL processing and marketing business represents one of the five largest NGL production asset groupings in North America. The profitability of the industry is based on the products extracted being of greater economic value as separate commodities than as components of natural gas.

Natural gas is a mixture of various hydrocarbon components, the most abundant of which is methane. The higher value hydrocarbons, which include ethane (C2), propane (C3), butane (C4) and pentanes-plus (C5+), are generally in gaseous form at the pressures and temperatures under which natural gas is gathered and transported. The basis of the NGL industry is the recovery of these higher value hydrocarbons from natural gas for sale in a liquid form. In Canada, approximately 90% of NGLs are a by-product of natural gas processing, with 10% resulting from the refining of crude oil. Approximately 75% of NGL production in Canada results from natural gas production in Alberta.

The NGL value chain begins with the gathering of gas that is produced. The gas then gets processed through processing plants, extraction facilities and fractionation facilities in order to remove high value NGLs, as well as water, sulphur and other impurities. The value chain culminates with the transportation and eventual sale of NGLs to the final customer.

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NGL Extraction

The heart of the NGL value chain lies in the extraction of NGLs from natural gas, which takes place in a number of steps at extraction facilities. NGLs are recovered primarily at three types of extraction facilities: natural gas field plants, natural gas straddle plants and oil refineries. Field plants process raw natural gas, which is produced from wells in the immediate vicinity, to remove impurities such as water, sulphur and carbon dioxide prior to the delivery of natural gas to the major natural gas pipeline systems. Field plants also remove almost all pentanes-plus and as much as 65% of propane and 80% of butane in order to meet pipeline specifications. Most field plants do not remove ethane, but there is currently about 70,000 b/d of ethane produced from Alberta field plants out of a total 240,000 b/d of ethane production from western Canada. The NGLs extracted are generally removed in mixes (either ethane-plus or propane-plus), which must be further processed in subsequent steps to separate out the individual products. Approximately 40% of the 700 field plants in western Canada extract NGLs.

NGL Fractionation

NGL mix extracted at field plants is transported to fractionation facilities, which enhances its value by separating the mix into its components: ethane, propane, butane and pentanes-plus. Fractionation generally does not occur at field plants, but rather at a central location (although there is some fractionation capacity at certain field plants in Alberta). The NGL mixes are moved by truck or pipeline to fractionation centres, with the greater Edmonton region serving as the major fractionation centre in Alberta and one of the four main fractionation hubs in North America, along with Sarnia, Ontario, Conway, Kansas and Mont Belvieu, Texas. Once fractionated, the products are then transported to markets in Alberta or outside the province, by pipeline, truck or rail.

NGL Transportation

The efficient movement of NGL products in western Canada requires significant infrastructure, including transportation assets (pipelines, trucks, rail cars), storage facilities and terminals (rail and truck). The most efficient and the lowest cost means for moving NGL products to markets is by pipeline. The western Canadian NGL sector has an extensive pipeline network for the transportation of natural gas to field plants and extraction facilities, and NGLs to fractionation facilities, petrochemical complexes, underground storage facilities and the final customer. Truck and rail account for a smaller amount of the NGLs movement transported in Alberta, with pipelines serving as the main mode of transport.

NGL Storage

Storage assets offer a number of key strategic advantages, which include: (i) providing the necessary buffer between production of NGLs (which varies daily depending on gas flows and composition) and their consumption (which can vary from day to day depending on market needs); (ii) allowing NGL providers to store inventory to accommodate outages in gas processing and NGL fractionation plants; and (iii) exploiting seasonal price differentials that may develop over the course of a year (particularly for propane and butane).

Large NGL storage facilities in Alberta are located in the Fort Saskatchewan / Redwater area. Such facilities use salt caverns deep underground which are created by washing the salt away with water until an open space is made.

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NGL Marketing

The end uses for NGLs are abundant and expanding. While NGLs are generally used directly as an energy product and also as a feedstock for the petrochemical and crude oil refining industries, the specific uses for NGLs vary substantially by product.

Ethane is used primarily as feedstock for the petrochemical industry and as a miscible flood agent for enhanced oil recovery operations. A significant amount of the ethane produced in the western Canadian sedimentary basin is sold through long-term contracts for feedstock to Alberta's expanding petrochemical industry. The production of ethane provides a secure and stable source of revenue and contributes to the long-term economic viability and growth of the NGL infrastructure.

Propane, which makes up over 65% of propane-plus extracted from major extraction facilities, is the most versatile of the NGL products from a marketing perspective. Uses for propane include home and commercial heating, crop drying, food processing, cooking and motor fuel. Approximately 75% of Canadian propane is exported to the US.

Butane, which makes up approximately 25% of propane-plus produced in major extraction facilities, is used primarily in gasoline blending or in the production of Canadian iso-octane. Approximately 25% of Canadian butane is exported to the US.

Pentanes-plus, which represents less than 10% of propane-plus produced at major extraction facilities, is used as a diluent to increase the viscosity of heavy crude oil for shipping through pipelines and as a refinery feedstock to make gasolines. Virtually all pentanes-plus in Alberta and Saskatchewan are used for this purpose.

Commercial Arrangements

Extraction

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

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For ethane, market prices usually consist of a shrinkage gas cost which flows through to ethane buyers, and an additional fixed fee to cover plant extraction costs. As a result, the ethane operations of an extraction facility generally generate a relatively predictable cash flow stream.

However, an extraction facility's other revenues are often tied to the market prices of propane, butane and pentanes-plus. The majority of the facility's costs to produce propane-plus are shrinkage gas and therefore the plant's profitability is influenced by the relative spread between natural gas prices and NGL product prices, often referred to as the "frac spread". The impact on margins can be significant when changes in the prices of NGLs and natural gas occur at different rates or move in different directions.

Generally, the commercial structure of the propane-plus business at extraction plants offers greater leverage to a favourable shift in commodity prices than the ethane business. Since the prices of propane, butane and pentanes-plus are set in the open market and are linked to the price of oil, and the costs of these products are primarily tied to the cost of natural gas, the profitability of a propane-plus producer is driven by the relative spread between these two commodities. Favourable movements in the spread between these prices offer substantial upside to a propane-plus producer. Most extraction facilities have profit sharing arrangements for propane-plus with exposure to both price and volume. Certain facilities have the frac spread exposure shifted onto buyers of propane-plus through the use of cost-of-service agreements.

Fractionation

While fluctuations in the frac spread are of particular importance in determining the profitability of most extraction plants, the financial performance of fractionation facilities is not frac spread dependent. A fractionation facility provides a package of services, which may include transportation of the NGL mix to the facility; fractionation of an incoming ethane-plus or propane-plus mixture into specification ethane, propane, butane and pentanes-plus; storage of NGLs at the facility; distribution and terminalling of the specification products; and marketing of the products. The facility receives a fee for these services which varies depending upon the complexity of the services provided. The expense side of the equation includes operating costs associated with gathering, transporting, fractionating, storing and distributing the NGL mix. Hence, profit is earned not on the spread differential between natural gas and NGLs, but on the difference between the fees charged and the costs incurred for the service provided. Alternatively, the owner of a fractionator may purchase NGL streams in the field for its own account, transport and process the stream, then sell the resulting products in the Edmonton or downstream market. In this case, its profit will be the difference between the sales prices it receives and the sum of its purchase price for the NGL stream and its costs of production (transportation, fractionation, storage).

Midstream services and marketing assets

Midstream NGL Acquisition

On December 13, 2005 Provident completed the Midstream NGL Acquisition and acquired the Midstream NGL Business.

The Assets

The Midstream NGL Business unit extracts, processes, stores, transports and markets NGLs. This is accomplished within two integrated systems and complementary assets. The Redwater system is comprised of three core assets:

·   100% ownership of the Redwater NGL fractionation facility, a 65,000 barrels per day (bbl/d) fractionation, storage and transportation facility that includes 12 pipeline receipt and delivery points, railcar loading facilities with direct access to rail facilities, two propane truck loading facilities, and six million gross barrels of salt cavern storage. The facility can process high-sulphur NGL streams and is one of only two facilities in western Canada capable of extracting ethane from the natural gas liquids stream.

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·   43.3% ownership of the 38,500 bbl/d Younger NGL extraction plant located at Taylor in north eastern British Columbia that supplies 16,700 bbl/d of net NGLs for processing at Redwater.

·   100% ownership of the 565 kilometer proprietary Liquids Gathering System ("LGS") that runs along the Alberta-British Columbia border providing access to a highly active basin for liquids-rich natural gas exploration and exploitation. Provident also has long-term shipping rights on the Pembina Peace Pipeline that extends the product delivery transportation network through to the Redwater fractionation facility.

The recently acquired Empress/Sarnia system is comprised of 5 core assets:

·   Approximately 2.0 bcf/d of extraction capacity at Empress Alberta. This is the combination of 60% ownership of the 1.2 bcf/d capacity Provident Empress NGL Extraction plant, 12.4% ownership in the 1.1 bcf/d capacity ATCO Plant, 8.3% ownership in the 2.4 bcf/d capacity Duke Plant and 33.0% ownership in the 2.7 bcf/d capacity BP Empress 1 Plant.

·   100% ownership of a 50,000 bbl/d debutanizer at Empress, Alberta.

·   50% ownership in the 130,000 bbl/d Kerrobert Pipeline and 2.5 mmbbl underground storage facility near Kerrobert, Saskatchewan which facilitates injection into the Enbridge Pipeline System. Along the Enbridge Pipeline System, Provident holds 18.3 % ownership of 300,000 bbls of Superior Storage staging facility and 18.3 % ownership of the 6,600 bbl/d Superior Depropanizer.

·   In Sarnia, Ontario, 10.3% ownership of an approximately 150,000 bbl/d fractionator, 1.7 mmbbl of raw product storage capacity and 18% of 5.0 mmbbl of finished product storage and rail, truck and pipeline terminalling.

·   49% interest in a partnership which owns the 6.9 mmbbl Marysville Underground Storage Terminal.

In addition, the Midstream NGL Acquisition included the acquisition by Provident of 100% ownership in the NGL marketing group Kinetic, which operates a fleet of approximately 700 rail cars and a propane distribution terminal at Lynchburg, Virginia.

Midstream and marketing services

Provident's midstream services offer customers several types of services and contractual arrangements, which include:

Fee for service processing: In these arrangements, NGL owners (typically natural gas producers) deliver their NGLs to Provident and pay fees for the transportation, fractionation, short term storage and distribution of their NGL barrels. The NGL owner is responsible for marketing their product.

Marketing Services: This service involves NGL owners delivering their product to Provident, with Provident taking title to the product. Provident pays the NGL owner an amount that is a delivery price of raw NGLs which is discounted to postings. The discounted purchase price that Provident pays for the product covers the costs of transportation, fractionation, storage, and marketing of the NGLs.

Storage: NGL owners pay fees to Provident to store their NGLs.

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Transport and Distribution: NGL owners or purchasers pay fees to transport NGLs through the LGS pipeline and use rail and truck loading facilities at Redwater, Sarnia, Marysville and Lynchburg.

 The Contracts

At the Redwater facility, approximately 75% of the available capacity is contracted through fee-for-service or fixed margin arrangements with major oil and natural gas producers and petrochemical businesses. As a result of these contracts, approximately 68% of Redwater's system capacity is contracted for 10 years or longer.

As with most Alberta straddle plants, all ethane produced from Provident's collective Empress interests is sold under long term contracts.

Plant Capacities and Throughput

The Redwater facility (100% ownership) was constructed between 1996 and 1998. It is the most modern facility of its type in Canada and is currently designed for throughput capacity of 65,000 bpd of NGLs with an expectation to average approximately 63,000 bpd.

The Provident Empress plant (60% ownership) was commissioned in September 1996 and subsequently expanded in 1999 and 2003. It is one of the newest and most cost efficient facilities at Empress. The plant has a design capacity of 1.2 bcf/d to extract ethane and propane-plus.

The BP Empress 1 plant (33% ownership) base plant was commissioned in 1971 with expansions commissioned in 1994 and 2005. The base plant has a capacity of 1.7 bcf/d to extract ethane and propane-plus. The 1994 train addition has 1 bcf/d capacity to extract propane-plus.

The Duke plant (8.3% ownership) was commissioned in 1964. It has a capacity of 2.4 bcf/d and has the following unique aspects (1) an airstrip; (2) treatment for ethane to remove CO₂; (3) a Ferus CO₂ plant hosted on a shared operating cost basis; (4) the only plant at the Empress Complex with full ethane-plus fractionation facilities; and (5) the ability to dispatch products by truck, rail, the IPF Jenner Pipeline, the Kerrobert Pipeline, and the PTC Pipeline.

The ATCO Plant (12.4% ownership) was commissioned in 1982, and expanded in 1999, and has an extraction capacity of 1.1 bcf/d.

The Provident Debutanizer (100% ownership) was commissioned at the end of 2005. It has a design capacity of 50,000 bbl/d of propane-plus and will remove condensate currently delivered to the Kerrobert Pipeline.

The Kerrobert Pipeline (50% ownership) is an NEB regulated pipeline constructed in 1971 to deliver propane-plus product from the Empress Comples to Kerrobert Storage near Kerrobert, Saskatchewan. It has a capacity of 130,000 bbl/d. Kerrobert Storage was also developed in 1971 and has a design capacity of 2.5 mmbbls.

Superior Storage (18.3% ownership) has a design capacity of 300,000 bbls and was built to accommodate the change in shipping rates within the Enbridge Pipeline system.

The Superior Depropanizer was built in 1991 and is designed to process approximately 10,000 bbl/d of propane-plus and extract 6,600 bbl/d of propane.

Sarnia Fractionation (10.3% ownership) began operations in 1970. It has an average capacity of approximately 150,000 bbl/d.

Provident had a 49% partnership interest in the Marysville Partnership which owns the Marysville Underground Storage Terminal. This interest was sold in February 2006 for US $12.5 million.

MARKET FOR SECURITIES

The outstanding Trust Units of the Trust are listed and posted for trading on the TSX under the symbol PVE.UN and the NYSE under the symbol PVX.

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The Trust Units were previously listed on the AMEX prior to December 16, 2005, at which time the Trust Units began trading on the NYSE. The 8.75% Debentures, 8% Debentures, Initial 6.5% Debentures and Supplemental 6.5% Debentures of the Trust are listed and posted for trading on the TSX under the symbol PVE.DB.A, PVE.DB.B, PVE.DB.C and PVE.DB.D, respectively.

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

Toronto Stock Exchange

Trust Units

Period	High	Low	Volume (000's)
2005
January	11.82	11.17	5,795
February	12.60	11.90	10,143
March	12.49	11.60	10,185
April	12.44	11.82	5,428
May	12.65	12.19	6,746
June	13.05	12.40	3,777
July	13.87	12.91	4,877
August	14.40	13.05	6,997
September	14.19	13.68	4,342
October	14.42	12.79	7,538
November	12.98	12.29	9,155
December	13.45	12.55	14,092

8.75% Debentures

Period	High	Low	Volume
2005
January	110.00	107.75	12,830
February	114.00	109.56	33,090
March	113.00	106.01	22,310
April	113.27	107.29	16,920
May	113.50	110.27	48,030
June	117.50	110.28	23.890
July	125.19	112.52	104,805
August	129.25	118.00	22,920
September	128.54	116.00	18,340
October	130.41	115.12	19,810
November	118.14	110.29	5,890
December	122.00	114.43	3,750

8% Debentures

Period	High	Low	Volume
2005
January	110.25	105.25	10,460
February	110.00	105.52	117,600
March	109.59	104.50	23,380
April	110.75	105.03	14,130
May	110.00	103.50	10,010
June	108.02	105.50	6,590
July	115.00	108.50	14,030
August	119.50	107.90	16,680
September	120.99	111.00	17,830
October	121.00	102.02	23,090
November	110.83	105.50	1,670
December	114.86	105.03	4,660

Initial 6.5% Debentures

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Period	High	Low	Volume
2005
March	100.99	99.00	727,875
April	100.69	99.50	82,010
May	100.50	99.00	64,065
June	100.50	99.00	123,720
July	104.00	100.00	95,645
August	110.00	102.56	39,540
September	106.75	102.96	116,340
October	106.75	100.00	44,110
November	102.99	100.50	39,500
December	105.49	102.01	19,190

Note:

(1)The Initial 6.5% Debentures began trading on the TSX on March 1, 2005.

Supplemental 6.5% Debentures

Period	High	Low	Volume
2005
November(1)	100.00	99.00	267,260
December	101.97	99.50	171,900

Note:

(1)The Supplemental 6.5% Debentures began trading on the TSX on November 15, 2005.

American Stock Exchange/New York Stock Exchange

Trust Units

Period	High	Low	Volume (000's)
2005
January	9.63	9.15	15,550
February	10.24	9.64	20,644
March	10.40	9.52	28,079
April	10.09	9.48	17,143
May	10.18	9.74	14,017
June	10.55	9.98	15,388
July	11.35	10.65	13,549
August	11.99	10.70	24,946
September	12.19	11.53	15,512
October	12.38	10.84	24,585
November	11.10	10.37	19,111
December(1)	11.69	10.70	10,866

Note:

(1)The Trust Units ceased trading on the AMEX and began trading on the NYSE on December 16, 2005.

RECORD OF CASH DISTRIBUTIONS

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

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	Distribution Amount (Cdn$)		Distribution Amount (US$)(1)
2001 March - December	$	2.54	$	1.64
2002 January - December	$	2.03	$	1.29
2003 January - December	$	2.06	$	1.47
2004
January - December	$	1.44	$	1.10
2005
January - December	$	1.44	$	1.20
2006
January	$	0.12	$	0.10
February	$	0.12	$	0.10
March	$	0.12	$	0.10
Total to date for 2006	$	0.36	$	0.30

Since its inception, the Trust has paid an aggregate of $9.87 (US$7.00) in cash distributions to Unitholders.

Note:

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

DIRECTORS AND OFFICERS

The following are the names and municipality of residence of the directors and officers of Provident, their principal position with Provident and their principal occupations. The Trust does not have any directors or officers. All of the persons listed above have been engaged for more than five years in their present principal occupation or executive position with the same or associated companies except as indicated below:

Name and Background	Number of Trust Units Beneficially Owned or Controlled
G.D. Billing (2) of Calgary, Alberta is the Executive Chairman and a director of Superior Plus Inc., since 1998. He has been a director of Provident since 2001. Prior thereto he was President and Chief Executive Officer of Norcen Energy Ltd. an oil and gas exploration and production company, from 1994 to 1998. He is also a director of Capitol Energy Resources Ltd.	65,740(5)
Thomas W. Buchanan of Calgary, Alberta has been the Chief Executive Officer and a director of Provident since March 2001. Prior thereto he was Executive Vice President Corporate Development and Chief Financial Officer of Founders Energy Ltd. from October 1999 to March 2001. Prior thereto he was President and Chief Executive Officer of Founders Energy Ltd. from 1996 to October 1999. He is also a director of Churchill Energy Inc. and Hawk Energy Corp.	966,793(4)(5)

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Randall J. Findlay of DeWinton, Alberta has been the President and a director of Provident since March 2001. Prior thereto he was Executive Vice President and Chief Operating Officer of Founders Energy Ltd. from December 1999 to March 2001. Prior thereto Senior Vice President of TransCanada Pipelines Ltd., a pipeline company, and President and Chief Executive Officer of TransCanada Gas Processing L.P., a gas processing partnership, from June 1998 to August 1999. He is also a director of Canadian Helicopters Income Fund and TransAlta Power LP.	932,188(4)
Mr. Hugh A. Fergusson(1), (3) of Calgary, Alberta is the former Vice President and Director with Dow Chemical Canada Inc. He has been a director of Provident since 2005 and is also a director of Canexus Income Fund and Taylor NGL Limited Partnership.	5,000(5)
Norman R. Gish(2) of Calgary, Alberta is the President, Gish Consulting Inc., energy consultants. Prior thereto he was Chairman, President and Chief Executive Officer of Alliance Pipeline Ltd. and Aux Sable Liquid Products Inc. He has been a director of Provident since 2003 and is also a director of Falconbridge Limited, Railpower Technologies Corp. and Superior Plus Inc.	7,000
Bruce R. Libin(1), (3) of Calgary, Alberta is the Chairman and Executive Chairman and Chief Executive Officer of Destiny Resource Services Corp., a resource services company, since 1997 and December 2000, respectively. He has also been President of B.R. Libin Capital Corp., an investment, merchant banking and investment banking advisory services company since 1995. He has been a director of Provident since 2001 and is also a director of Winstar Resources Ltd.	97,403
Dr. Robert Mitchell(3) of Calgary, Alberta has been an independent businessman since September 2003. From 1984 to September 2003, he was Executive Vice President of Talisman Energy Inc. He has been a director of Provident since 2004 and is also a director of Winstar Resources Ltd.	6,000
Byron J. Seaman(3) of Calgary, Alberta is an independent businessman and private investor. He has been a director of Provident since 2001 and is also a director of Rider Resources Ltd.	35,068
M.H. (Mike) Shaikh(1) of Calgary, Alberta is the President of M.H. Shaikh Professional Corporation (Chartered Accountants). He has been a director of Provident since 2001 and is also a director of Churchill Energy Inc. and Mystique Energy Inc. and is an officer of Hawk Energy Corp.	57,634
Jeffrey T. Smith(2), (3) of Calgary, Alberta is an independent businessman and private investor. He has been a director of Provident since 2001 and is also a director of Compton Petroleum Ltd. and Cordero Energy Inc.	4,900
John B. Zaozirny(2) of Calgary, Alberta is counsel to the law firm of McCarthy Tétrault llp and Vice-Chairman of Canaccord Capital Corporation. He has been a director of Provident since 2001 and is also a director of Bankers Petroleum Ltd., Canadian Oil Sands Trust, Candax Inc., Computer Modelling Group Ltd., Fording Canadian Coal Trust, High Arctic Energy Services Trust, IPSCO Inc., Pengrowth Energy Trust, Petroworld Corp. and TerraVest Income Fund.	53,339

Notes:

(1)Member of the Audit Committee.

(2)Member of the Governance, Human Resources and Compensation Committee.

(3)Member of the Reserves, Operations and Environment, Health and Safety Committee.

(4)Includes Trust Units issuable upon exchange of exchangeable shares of Provident held by such director at an exchange ratio of 1.55261.

(5)Mr. Billing also holds $500,000 principal amount of the Initial 6.50% Debentures. Mr. Buchanan also holds $100,000 of the Supplemental 6.50% Debentures. Mr. Fergusson also holds $100,000 of the Supplemental 6.50% Debentures. Mr. Shaikh also holds $250,000 principal amount of the Supplemental6.50% Debentures. Mr. Gish also holds $20,000 principal amount of the 8.75% Debentures and also holds $50,000 principal amount of the Supplemental 6.50% Debentures.

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 Murray Buchanan

Co-President, NGL Services

Mr. Buchanan received his masters of business administration from Queen's University, as well as an honours bachelor of administration degree from Queen's University. Mr. Buchanan is responsible for commercial activities associated with Provident's midstream services business unit including natural gas liquids fractionation, storage, processing, marketing and transportation services. Murray joined Provident in 2005 following Provident's acquisition of the Empress midstream assets. He has over 25 years of NGL marketing and petroleum industry experience and had been president of Kinetic Resources for eight years.

Andrew Gruszecki

Co-President, NGL Services

Mr. Gruszecki received his honours bachelor of science in science from the University of Western Ontario and did his co-op master's of business administration at McMaster University and joined Provident in 2003. He brings over 25 years of experience and expertise in oil and NGL marketing, business development, and planning. From 2000 to 2003, he was senior manager of commercial operations at Williams Energy (Canada). Prior to joining Williams, Mr. Gruszecki was vice president of NGL Marketing for Coast Energy Canada. From 1997 to 1998, he was director of commercial operations at TransCanada Midstream and the former Novagas Canada. While at Novagas, Mr. Gruszecki oversaw commercial issues related to the planning, construction and implementation of the NGL business which included the construction of the Redwater fractionation facilities. Mr. Gruszecki began his career in the energy business in 1981 and held positions of increasing responsibility before joining Novagas in 1997.

David Holm

Executive Vice President, Strategy, Finance and Business Development and Corporate Secretary

Mr. Holm received his Bachelor of Commerce Degree from the University of Alberta and his Bachelor of Laws Degree from the University of Western Ontario. He was called to the Alberta Bar in 1986. Mr. Holm has spent the last six years in investment banking and most recently was Managing Director, North American Energy with TD Securities Inc. Prior to his move into investment banking, Mr. Holm practiced securities law for 15 years, most recently as a partner with Macleod Dixon LLP.

Gary Kline

Senior Vice President, Commercial Development and Risk Management

Mr. Kline received his bachelor of arts in economics from the University of Calgary. He later received his Canadian Securities Certificate from the Canadian Securities Institute. Mr. Kline has over 20 years of experience in the energy industry and before joining Provident in 2003, he was president of GRK Energy Consulting from 1998 to 2003. Mr. Kline has held a number of senior management positions including managing director of marketing and business development for Reliant Energy Canada from 1998 to 2002, vice president for natural gas and electricity at U.S. Generating Canada from 1996 to 1998, and manager of gas marketing at CanStates Gas Marketing from 1986 to 1996 Gary began his energy industry career as a regulatory analyst at TransCanada Pipelines in 1982.

Daniel J. O'Byrne

Executive Vice President, Operations and Chief Operating Officer

Mr. O'Byrne received his Bachelor of Science Degree in Petroleum Engineering from the University of Alberta and a Masters of Business Administration Degree from the University of Western Ontario. Mr.

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O'Byrne has over 25 years of diverse experience in the international and North American oil industry and has participated in major projects in Canada, the United Kingdom (North Sea), the Middle East, West Africa and other countries. His positions have included Division Vice President, Technical Services for Nexen Inc. (2001-2005); Vice President, Technical Services for Canadian Occidental/Westcana Energy Inc. (1998-2001); and Vice President, Operations-Yemen for Canadian Occidental Petroleum Ltd. (1997-1998); as well as numerous other management position with Canadian Occidental Petroleum Ltd. He is also a director of the Petroleum Technology Research Centre, a director of White Max Energy Ltd., and a past chair of the Canadian Oil Sands Network for Research and Development. He has contributed to the reserves and safety committees of the Canadian Associate of Petroleum Producers, is a member of the Association of Professional Engineers, Geologists and Geophysicists of Alberta and is one of the Society of Petroleum Engineers published authors.

Cameron Vouri

President, Canadian Oil and Gas Production Business Unit

Mr. Vouri obtained a Bachelor of Science (Petroleum Engineering) degree from New Mexico Institute of Mining and Technology in 1988. Prior to Mr. Vouri's appointment to his current position with Provident, he was Vice President and Chief Operating Officer of Provident since January 2003. Prior thereto he held the position of Vice President with Provident. Mr. Vouri held various senior management positions with Koch Exploration Canada, Ltd. from 1989 to 2000.

Mark N. Walker

Senior Vice President, Finance and Chief Financial Officer

Mark Walker is Senior Vice President of Finance and Chief Financial Officer of Provident. A member of Provident's senior leadership team, Mr. Walker is responsible for all finance, financial reporting, treasury, and compliance activities. Prior to the appointment to his current position, Mr. Walker served as controller and CFO from 1997 to 2002. Mr. Walker joined Provident's predecessor Founders in 1996 as controller.

Mr. Walker has over 19 years of experience in petroleum finance and accounting. Prior to joining Founders, Mr. Walker was team leader of financial reporting for Sceptre Resources, first joining that company in 1990. From 1988 to 1990, Mr. Walker was a revenue accountant with Dome Petroleum. Before Dome, Mr. Walker was an accountant with Hudson & Company from 1985 to 1988.

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

Committees of the Board

During the year ended December 31, 2005, the Board of Directors had three committees - the Audit Committee, the Reserves, Operations and Environmental, Health and Safety Committee, and the Governance, Human Resources and Compensation Committee. In addition, the Trust has established one additional committee in 2006 - the Disclosure Committee, which is comprised entirely of members of management. Membership in each committee is set forth below.

Audit Committee

The Audit Committee consists of Mr. M.H. (Mike) Shaikh (Chairman), Mr. Bruce R. Libin and Mr. Hugh A. Fergusson. All members of the Audit Committee are independent and financially literate, as determined by applicable securities legislation, and at least one member of the Committee is an "audit committee financial expert" as required by U.S. securities laws. The Audit Committee reviews the Trust's interim unaudited consolidated financial statements and annual audited consolidated financial statements

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and certain corporate disclosure documents including management's discussion and analysis and annual and interim earnings press releases before they are approved by the board of directors. The Committee also reviews and makes a recommendation to the board of directors in respect of the appointment and compensation of the external auditor and it monitors accounting, financial reporting, control and audit functions. The Audit Committee meets to discuss and review the audit plans of external auditors and is directly responsible for overseeing the work of the external auditor with respect to preparing or issuing the auditor's report or the performance of other audit, review or attest services, including the resolution of disagreements between management and the external auditor regarding financial reporting. The Committee questions the external auditor independently of management and reviews a written statement of its independence based on the criteria found in the recommendations of the Canadian Institute of Chartered Accountants. The Committee must be satisfied that adequate procedures are in place for the review of the Trust's public disclosure of financial information extracted or derived from its financial statements and it periodically assesses the adequacy of those procedures. The Audit Committee also must approve or pre-approve, as applicable, any non-audit services to be provided to the Trust by the external auditor. In addition, it reviews and reports to the board of directors on the Trust's risk management policies and procedures and reviews the internal control procedures to determine their effectiveness and to ensure compliance with the Trust's policies and avoidance of conflicts of interest. In conjunction with the Trust's whistleblower policy, the Committee has established procedures for dealing with complaints or confidential submissions which come to its attention with respect to accounting, internal accounting controls or auditing matters. See "Audit Committee Information" and Schedule A of this Annual Information Form for additional information relating to the Audit Committee.

Governance, Human Resources and Compensation Committee

The Governance, Human Resources and Compensation Committee consists of Mr. Jeffrey T. Smith (Chairman), Mr. Grant D. Billing, Mr. Norman R. Gish and Mr. John B. Zaozirny, all of whom are considered independent directors within the meaning of applicable securities legislation. The Committee is responsible for recommending to the board of directors suitable candidates for director positions. The selection assessment includes a wide array of factors deemed appropriate, all in the context of an assessment of the perceived needs of the board of directors and Provident at the time. In addition, the Committee assists the board of directors on corporate governance matters and in assessing the functioning and effectiveness of the Board.

The Governance, Human Resources and Compensation Committee's mandate also includes reviewing Provident's human resources policies and procedures and compensation and incentive programs. The Committee is responsible for assessing senior management's performance and recommending senior management compensation to the board of directors. The Committee reviews the adequacy and form of directors' compensation and makes recommendations designed to ensure that directors' compensation adequately reflects the responsibilities of the board of directors. The Committee also administers the incentive plans of the Trust and makes recommendations to the board of directors respecting grants of awards thereunder.

Reserves, Operations, Environment, Health and Safety Committee

The Reserves, Operations and Environmental, Health and Safety Committee consists of Mr. Jeffrey T. Smith (Chairman), Dr. Robert Mitchell, Mr. Bruce R. Libin, Mr. Byron J. Seaman and Mr. Hugh A. Fergusson, all of whom are considered independent directors within the meaning of applicable securities legislation. The Committee assists the board in its oversight of the oil and natural gas reserves evaluation process and the public disclosure of reserves data and related information as required by National Instrument 51-101; the operations of Provident, including operating activities, operating expenses and capital expenditure budget; and the environmental, health and safety issues, including the evaluation of Provident's programs, controls and reporting systems, and compliance with applicable laws, rules and regulations.

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 Disclosure Committee

The Disclosure Committee is comprised of the Chief Executive Officer, President, the Executive Vice President, Operations and Chief Operating Officer, the Executive Vice President, Finance and Strategy and Corporate Secretary, the Senior Vice President, Finance and Chief Financial Officer, the Co- Presidents, Midstream Business Unit, the Senior Vice President, Commercial Development and Risk Management, the President, Canadian Oil and Gas Production Business Unit, the Corporate Controller, the Senior Manager, Investor Relations and Communications and the Assistant Corporate Secretary of Provident. The Disclosure Committee's primary responsibilities are to oversee the Trust's disclosure practices and to ensure the Trust meets all Canadian and U.S. regulatory disclosure requirements. In particular, the Disclosure Committee will review and, as necessary, help revise the Trust's controls and other procedures to ensure that information required to be disclosed to securities regulators and the Toronto Stock Exchange and New York Stock Exchange, and other information the Trust will disclose to the public is recorded, processed, summarized and reported accurately and on a timely basis. In addition, the Committee will determine when events, developments, changes or other facts constitute material information or a material change in the affairs of Provident and will review and supervise the preparation of the Trust's (i) Annual Information Form, Information Circular, annual and interim financial statements and any other information filed with the Canadian and U.S. securities regulators; (ii) press releases containing financial information, earnings guidance, forward looking statements, information about operations, or any other information material to the Trust's security holders; (iii) correspondence broadly disseminated to shareholders; and (iv) other relevant written and oral communications or presentations.

The Committee will also review risk factors, underlying assumptions and forward looking statement language for written and oral communications which contain forward looking information and review that there is a reasonable basis for any conclusions, forecasts or projections contained in such information.

Conflicts of Interest

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

As at the date hereof, Provident is not aware of any existing or potential material conflicts of interest between Provident and a director or officer of Provident.

AUDIT COMMITTEE INFORMATION

Composition of the Audit Committee

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

Audit Committee Charter

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

Relevant Education and Experience of Each Audit Committee Member

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

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Name	Independent	Financially Literate	Relevant Education and Experience
M.H. (Mike) Shaikh	Yes	Yes	Mr. Shaikh holds the degree of Bachelor of Commerce and is a Chartered Accountant. As a Chartered Accountant, Mr. Shaikh attained experience in preparing, auditing, analyzing and evaluating financial statements. Mr. Shaikh has an understanding of the accounting principles used by Provident as well as the implications of those accounting principles on Provident's financial results. Mr. Shaikh has also obtained significant financial experience and exposure to accounting and financial issues as the President of M.H. Shaikh Professional Corporation and in his role as a director and audit committee member of various public companies. He was also a board member of the Alberta Securities Commission from 2003 to 2006.
Bruce R. Libin, Q.C.	Yes	Yes	Mr. Libin holds the degree of Bachelor of Commerce (Honours), Master of Business Administration and Juris Doctoris. Mr. Libin has obtained significant financial experience and exposure to accounting, disclosure, internal controls and financial issues during his legal practice, his business experience (including as Chief Executive Officer of Beau Canada Exploration Ltd. and as Executive Chairman and Chief Executive Officer of Destiny Resource Services Corp.) and his service on the audit committee of several boards of directors, including Amoco Canada Petroleum Company Limited, Maxx Petroleum Ltd., Mark's Work Warehouse Ltd., Calgary Health Region, Southern Alberta Institute to Technology, NQL Drilling Tools Ltd., and Winstar Resources Ltd.
Hugh A. Fergusson	Yes	Yes	Mr. Fergusson holds the degrees of Bachelor of Arts and Bachelor of Laws. He has also completed Advanced Management Programs at the University of Western Ontario and Northwestern University. He is an independent businessman and Corporate Director. Mr. Fergusson practiced law for five years following which he was employed by the Dow Chemical Company (and related companies) for 27 years until he retired in 2004. During his career with Dow, Mr. Fergusson obtained significant financial experience and exposure to accounting and financial issues through a series of roles including commercial and business leadership largely related to hydrocarbons and energy. In addition to being a director of a number of Dow subsidiaries, Mr. Fergusson was Chairman of Petromont Inc. from 2002 until 2004 and a member of its Audit Committee from 2002 until 2004.

External Auditor Service Fees

The following table sets forth information about the fees billed to the Trust for professional services provided by PricewaterhouseCoopers LLP during fiscal 2005 and 2004:

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(CDN$)	2005		2004
Audit Fees	$	929,000	$	868,000
Audit-Related Fees		30,000		90,750
Tax Fees		776,300		375,000
All Other Fees		-		-
Total	$	1,735,300	$	1,333,750

INFORMATION CONCERNING THE OIL AND GAS INDUSTRY

Canadian Government Regulation

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

Pricing and Marketing - Oil

Producers of oil negotiate sales contracts directly with oil purchasers, with the result that the market determines the price of oil. Such price depends in part on oil quality, price of competing oils, distance to market and the value of refined products. Oil exporters are also entitled to enter into export contracts and export oil provided that, for contracts, which do not exceed one year in the case of light crude oil and two years in the case of heavy crude oil, an export order must be obtained from the National Energy Board prior to the export. Any export pursuant to a contract of longer duration must be made pursuant to a National Energy Board export licence and Governor in Council approval.

Pricing and Marketing - Natural Gas

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

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

The North American Free Trade Agreement

On January 1, 1994 the North American Free Trade Agreement ("NAFTA") among the governments of Canada, the United States and Mexico became effective. NAFTA carries forward most of the material energy terms contained in the Canada-U.S. Free Trade Agreement. In the context of energy resources, Canada continues to remain free to determine whether exports to the U.S. or Mexico will be allowed

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provided that the restrictions are otherwise justified under certain provisions of the General Agreement on Tariffs and Trade and then only if any export restrictions do not: (i) reduce the proportion of the energy resource exported relative to the total supply of energy resource (based upon the proportions prevailing in the most recent 36 months); (ii) impose an export price higher than the domestic price; or (iii) disrupt normal channels of supply. All three countries are prohibited from imposing minimum export or import price requirements.

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

Provincial Royalties and Incentives

In addition to federal regulation, each province has legislation and regulations, which govern land tenure, royalties, production rates, environmental protection and other matters. The royalty regime is a significant factor in the profitability of oil and natural gas production. Royalties payable on production from lands other than Crown lands are determined by negotiations between the mineral owner and the lessee. Crown royalties are determined by governmental regulation and are generally calculated as a percentage of the value of the gross production, and the rate of royalties payable generally depends in part on well productivity, geographical location, field discovery data and the type or quality of the petroleum product produced.

From time to time the governments of Canada and Alberta have established incentive programs, which have included royalty rate reductions, royalty holidays and tax credits for the purpose of encouraging oil and natural gas production and enhanced production projects.

Alberta

In Alberta, a producer of oil or natural gas is entitled to a credit against the royalties payable to the Crown by virtue of the ARTC program. The ARTC rate is based on a price-sensitive formula and varies between 75 percent for prices at or below the royalty tax credit reference price of $100 per m³ decreasing to 25 percent for prices above the royalty tax credit reference price of $210 per m³. The ARTC rate will be applied to a maximum annual amount of $2,000,000 of Alberta Crown royalties payable for each producer or associated group of producers. Crown royalties on production from producing properties acquired from corporations claiming maximum entitlements to ARTC will generally not be eligible for ARTC. The rate is established quarterly based on the average par price, as determined by the Alberta Department of Energy.

On October 13, 1992, the Alberta government announced major changes to its royalty structure and permanent incentives for exploring and developing oil and gas reserves. The significant changes announced which remain in force include the following: (i) the first wells drilled in new oil pools discovered on or after October 1, 1992 will have a permanent one year oil royalty holiday, subject to a $1,000,000 cap and a reduced royalty rate thereafter; (ii) reduction of royalties on pre-October 1, 1992 production of oil and gas; (iii) incentives by way of royalty holidays and reduced royalties on reactivated, low productivity and horizontal re-entry of vertical oil wells; (iv) introduction of separate par pricing for light, medium and heavy oil; and (v) modification of the royalty formula structure to provide for sensitivity to price fluctuations.

Environmental Regulation

The oil and natural gas industry is currently subject to environmental regulations pursuant to provincial and federal legislation. Environmental legislation provides for restrictions and prohibitions on releases or emissions of various substances produced in association with certain oil and gas industry operations. In addition, legislation requires that well and facility sites be abandoned and reclaimed to the satisfaction of provincial authorities. A breach of such legislation may result in the imposition of fines and penalties, the suspension or revocation of necessary licenses and civil liability. Environmental legislation in Alberta has been consolidated into the Environmental Protection and Enhancement Act (Alberta), which took

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effect on September 1, 1993. The Environmental Protection and Enhancement Act (Alberta) imposes stricter environmental standards, requires more stringent compliance and reporting and significantly increases penalties for non-compliance.

Exports from Canada

In order to export oil or natural gas from Canada, certain approvals are required from the National Energy Board and the Government of Canada. The approval(s) required are dependent on the hydrocarbon substance being exported and the length of the proposed export arrangement.

RISK FACTORS

The Trust Units do not represent a traditional investment in the oil and natural gas industry. Prospective purchasers of the Trust Units should carefully consider the information set forth below and the other information set forth herein before deciding to invest in the Trust Units.

The Trust is a limited purpose trust, which will be entirely dependent upon the operations and assets of Provident through its ownership directly and indirectly, of the natural gas midstream, NGL processing and marketing business and the oil and natural gas properties. Accordingly, the Trust is dependent upon the ability of Provident to meet its interest and principal repayment obligations under the notes which the Trust may issue from time to time and to pay royalties. Provident's income will be received from the cash flow generated from the natural gas midstream, NGL processing and marketing business and from the production of oil and natural gas from Provident's existing resource properties and will be susceptible to the risks and uncertainties associated with the oil and natural gas industry and the NGL processing business generally. If the oil and natural gas reserves associated with Provident's resource properties are not supplemented through additional development or the acquisition of additional oil and natural gas properties, the ability of Provident to meet its obligations to the Trust may be adversely affected. Unitholders should consider carefully the information contained herein and, in particular, the following risk factors:

Oil and Gas Production Risk Factors

Exploitation and Development

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

Operations

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

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

Oil and Natural Gas Prices

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

Marketing

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

Capital Investment

The timing and amount of capital expenditures will directly affect the amount of income for distribution to Trust Unitholders. Distributions may be reduced, or even eliminated, at times when significant capital or other expenditures are made.

Debt Service

Provident currently has a term credit facilities of $750 million and US$100 million. Variations in interest rates and scheduled principal repayments could result in significant changes in the amount required to be applied to debt service before payment of any amounts to the Trust. Although it is believed that the bank line of credit is sufficient, there can be no assurance that the amount will be adequate for the financial obligations of Provident or that additional funds can be obtained.

The lender has been provided with security over substantially all of the assets of Provident. If Provident becomes unable to pay its debt service charges or otherwise commits an event of default such as bankruptcy, the lender may foreclose on or sell Provident's oil and gas properties free from or together with the Provident Royalties.

Reserves

Although McDaniel, NSA, CGA and Provident have carefully prepared the reserve figures included herein such figures are estimates and no assurance can be given that the indicated levels of reserves will be produced. Probable reserves estimated for properties may require revision based on the actual development strategies employed to prove such reserves. Declines in the reserves of Provident, which are not offset by the acquisition, or development of additional reserves may reduce the underlying value of Trust Units to Trust Unitholders. The value of the Trust Units attributable to the oil and gas reserves will have no value once all of the oil and natural gas reserves of Provident have been produced. As a result, holders of Trust Units will have to obtain the return of capital invested out of cash flow derived from their investment in such Trust Units.

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Environmental Concerns

The oil and natural gas industry is subject to environmental regulation pursuant to local, provincial and federal legislation. A breach of such legislation may result in the imposition of fines or issuance of clean up orders in respect of Provident or its oil and gas properties. Such legislation may be changed to impose higher standards and potentially more costly obligations on Provident. Although Provident has established a reclamation fund for the purpose of funding its currently estimated future environmental and reclamation obligations based on its current knowledge, there can be no assurance that the Trust will be able to satisfy its actual future environmental and reclamation obligations.

Delay in Cash Distributions

In addition to the usual delays in payment by purchasers of oil and natural gas to the operators of oil and gas properties, and by the operator to Provident, payments between any of such parties may also be delayed by restrictions imposed by lenders, delays in the sale or delivery of products, delays in the connection of wells to a gathering system, blowouts or other accidents, recovery by the operator of expenses incurred in the operation of oil and gas properties or the establishment by the operator of reserves for such expenses.

Reliance on Provident

Unitholders will be dependent on the management of Provident in respect of the administration and management of all matters relating to Provident's oil and gas properties, the royalties, the Trust and Trust Units. Investors who are not willing to rely on the management of Provident should not invest in the Trust Units.

Depletion of Reserves

The Trust has certain unique attributes, which differentiate it from other oil and gas industry participants. Distributions of Distributable Cash in respect of Provident's oil and gas properties, absent commodity price increases or cost effective acquisition and development activities, will decline over time in a manner consistent with declining production from typical oil, natural gas and natural gas liquids reserves. Provident will not be reinvesting cash flow in the same manner as other industry participants. Accordingly, absent capital injections, Provident's initial production levels and reserves will decline.

Provident's future oil and natural gas reserves and production, and therefore its cash flows, will be highly dependent on Provident's success in exploiting its reserve base and acquiring additional reserves.  Without reserve additions through acquisition or development activities, Provident's reserves and production will decline over time as reserves are exploited.

To the extent that external sources of capital, including the issuance of additional Trust Units (through public offerings, the DRIP or otherwise) become limited or unavailable, Provident's ability to make the necessary capital investments to maintain or expand its oil and natural gas reserves will be impaired. To the extent that Provident is required to use cash flow to finance capital expenditures or property acquisitions, the level of Distributable Cash will be reduced.

There can be no assurance that Provident will be successful in developing or acquiring additional reserves on terms that meet the Trust's investment objectives.

Natural Gas Midstream, NGL Processing and Marketing Business Risk Factors

Facilities Throughput

The volumes of natural gas processed through Provident's natural gas midstream, NGL processing and marketing business and of NGLs and other products transported in the pipelines depend on production of

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natural gas in the areas serviced by the business and pipelines. Without reserve additions, production will decline over time as reserves are depleted and production costs may rise. Producers may shut in production at lower product prices or higher production costs. Producers in the areas serviced by the business may not be successful in exploring for and developing additional reserves, and the gas plants and the pipelines may not be able to maintain existing volumes of throughput. Commodity prices may not remain at a level which encourages producers to explore for and develop additional reserves or produce existing marginal reserves.

The rate and timing of production from proven natural gas reserves tied into the gas plants is at the discretion of the producers and is subject to regulatory constraints. The producers have no obligation to produce natural gas from these lands.

Provident's natural gas midstream, NGL processing and marketing business is connected to various third party trunkline systems. Operational disruptions or apportionment on those third party systems may prevent the full utilization of the business.

Over the long term, business will depend, in part, on the level of demand for NGLs and natural gas in the geographic areas in which deliveries are made by pipelines and the ability and willingness of shippers having access or rights to utilize the pipelines to supply such demand. Provident cannot predict the impact of future economic conditions, fuel conservation measures, alternative fuel requirements, governmental regulation or technological advances in fuel economy and energy generation devices, all of which could reduce the demand for natural gas and NGLs.

Bank Financing

Variations in interest rates and scheduled principal repayments could result in significant changes in the amount required to be applied to debt service before payment of any amounts to the Trust. Although it is believed that this credit facility is sufficient, there can be no assurance that the amount will be adequate for the financial obligations of Provident or that additional funds can be obtained.

The lenders have been provided with security over substantially all of the assets of Provident. If Provident becomes unable to pay its debt service charges or otherwise commits an event of default such as bankruptcy, the lenders may foreclose on or sell Provident's oil and gas properties and other assets.

Operational Matters and Hazards

Provident's operations will be subject to common hazards of the natural gas processing and pipeline transportation business. The operation of Provident's natural gas midstream, NGL processing and marketing business could be disrupted by natural disasters or other events beyond the control of Provident. A casualty occurrence could result in the loss of equipment or life, as well as injury and property damage. Provident carries insurance coverage with respect to some, but not all, casualty occurrences in amounts customary for similar business operations, which coverage may not be sufficient to compensate for all casualty occurrences.

The operation of Provident's natural gas midstream, NGL processing and marketing business will involve many risks, including the breakdown or failure of equipment, information systems or processes, the performance of equipment at levels below those originally intended (whether due to misuse, unexpected degradation or design, construction or manufacturing defects), failure to maintain an adequate inventory of supplies or spare parts, operator error, labour disputes, disputes with owners of interconnected facilities and carriers and catastrophic events such as natural disasters, fires, explosions, fractures, acts of eco-terrorists and saboteurs, and other similar events, many of which are beyond the control of the Trust or Provident. The occurrence or continuance of any of these events could increase the cost of operating facilities and/or reduce its processing or throughput capacity, thereby reducing cash flow.

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Operating and Capital Costs

Operating and capital costs of Provident's natural gas midstream, NGL processing and marketing business may vary considerably from current and forecast values and rates and represent significant components of the cost of providing service. In general, as equipment ages, maintenance capital expenditures and maintenance expenses with respect to such equipment may increase over time. Distributions may be reduced if significant increases in operating or capital costs are incurred.

Although operating costs are to be recaptured through the tariffs charged on natural gas volumes processed and oil and NGLs transported, respectively, to the extent such charges escalate, producers may seek lower cost alternatives or stop production of their natural gas.

Competition

Provident's natural gas midstream, NGL processing and marketing business is subject to competition from other gas processing plants which are either in the general vicinity of the gas plants or have gathering systems that are or could potentially extend into areas served by the gas plants. The pipelines and storage, terminal and processing facilities are also subject to competition from other pipelines and storage, terminal and processing facilities in the areas they serve, and the gas products marketing business is subject to competition from other marketing firms.

Producers in Alberta compete with producers in other regions to supply natural gas and gas products to customers in North America and the natural gas and gas products industry also competes with other industries to supply the fuel, feedstock and other needs of consumers. Such competition may have an adverse effect on the production of natural gas and gas products in Alberta and, as a result, on the demand for Provident's services.

Regulatory Intervention

Pipelines and facilities can be subject to common carrier and common processor applications and to rate setting by regulatory authorities in the event agreement on fees or tariffs cannot be reached with producers. To the extent that producers believe processing fees or tariffs respecting pipelines and facilities are too high, they may seek rate relief through regulatory means.

Environmental Considerations

Major equipment failure, release of toxic substances or pipeline rupture could result in damage to the environment and Provident's natural gas midstream, NGL processing and marketing business, death or injury and substantial costs and liabilities to third parties. Provident may not be able to insure against these events or may elect not to insure because of high premium costs or for other reasons. If, at any time, appropriate regulatory authorities deem any one of the gas plants unsafe, they may order it to be shut down.

The gas processing and gathering industry is regulated by federal and provincial environmental legislation. Activities that do not meet regulatory standards or that breach such legislation may result in the imposition of fines, penalties and suspension of operations. It is possible that increasingly strict environmental and safety laws will be implemented, which could result in substantial costs of compliance.

    Abandonment

Provident will be responsible for compliance with all laws and regulations regarding abandonment of Provident's natural gas midstream, NGL processing and marketing business at the end of their economic life, which abandonment costs may be substantial. It is not possible to estimate the abandonment costs at this time as they will be a function of regulatory requirements at the time of abandonment.

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Frac Spread

The Midstream NGL Business' exposure to commodity price risk applies mainly to frac spread. The MidstreamNGL Business is exposed to the relative price differential between the NGL produced and the shrinkage gas used to replace the heat content removed during extraction of the NGL from the natural gas stream. The amount of profit or loss made on this portion of the MidstreamNGL Business will increase or decrease as the difference between the price of the applicable NGL and the price of natural gas varies. The Midstream NGL Business will increase Provident's exposure to frac spread which could result in a material variability of cash flow generated by the Midstream NGL Business. Any such variability could negatively affect the Trust and the cash distributions of the Trust. Frac spread is of less risk for Provident's natural gas midstream and NGL processing business.

Reliance on Principal Customers and Operators

Provident will rely on several significant customers to purchase product from the Midstream NGL Business. Ethane is predominately purchased by Nova Chemicals Corporation and Dow Chemicals Canada Inc. A significant amount of propane is purchased by Ferrellgas, a division of Ferrellgas Partners L.P. and AmeriGas Partners L.P. EnCana Corporation and its affiliates ("EnCana") will purchase the majority of the condensate from the EnCana Empress Debutanizer and will also be the principal supplier of natural gas and NGL for the Midstream NGL Business. BP Canada operates the BP E1 Plant at Empress, Alberta and the west to east system described herein. EnCana currently operates the EnCana Empress Plant. If for any reason these parties were unable to perform their obligations under the various agreements with Provident, the revenue and distributions of the Trust, and the operations of the MidstreamNGL Business could be negatively impacted.

General Risk Factors

Risks Associated With the Level of Foreign Ownership

Generally, a trust cannot qualify as a "mutual fund trust" for the purposes of the Tax Act if it is established or is being maintained primarily for the benefit of non-residents. Although not without uncertainty, this is generally accepted to exist in most situations where Non-Resident holders own significantly in excess of 50% of the aggregate number of Trust Units issued and outstanding. However, there is currently an exception to the non-resident ownership restriction where not more than 10% of the trust's property has at any time consisted of "taxable Canadian property". The Department of Finance has indicated that it will be consulting with the private sector regarding non-resident ownership of mutual fund units. No formal consultations have been announced in this regard. There can be no assurance that the treatment of mutual fund trusts will not be changed in a manner which adversely affects Trust Unitholders.

The retention of "mutual fund trust" status under the Tax Act is important for both resident and non-resident holders of Trust Units and not just for holders of Trust units held within Canadian tax exempt plans. The loss of such status could be expected to have a significant adverse effect on the market price of the Trust Units. The importance of mutual fund status and the consequences of losing such status are set forth below:

(a) By virtue of its status as a mutual fund trust, the Trust has been accepted for registration effective March 6, 2001 as a "registered investment" for registered retirement savings plans ("RRSPs"),registered retirement income funds ("RRIFs"), and deferred profit sharing plans ("DPSPs") (collectively, "Exempt Plans"). As such, Trust Units are qualified investments for Exempt Plans as well as registered education savings plans ("RESPs") and if the Trust's status as a "registered investment" is revoked in any year by virtue of ceasing to be a "mutual fund trust" the Trust Units would remain as qualified investments for Exempt Plans and RESPs until the end of the year following such year;

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(b) Where at the end of any month an Exempt Plan or a RESP holds Trust Units that are not qualified investments, the Exempt Plan or RESP must, in respect of that month, pay a tax under Part XI.1 of the Tax Act equal to 1 percent of the fair market value of the Trust Units at the time such Trust Units were acquired by the Exempt Plan or RESP. An RRSP or RRIF holding Trust Units that are not qualified investments would become taxable on income attributable to the Trust Units while they are not qualified investments (including the entire amount of any capital gain arising on a disposition of the non-qualified investment). RESPs which hold Trust Units that are not qualified investments may have their registration revoked by the Canada Revenue Agency;

(c) The loss of mutual fund trust status would render the Trust liable for the payment of a tax under Part XII.2 of the Tax Act in respect of certain designated income. The payment of Part XII.2 tax by the Trust could have adverse consequences to Unitholders who are not residents of Canada and to certain Unitholders which are tax exempt entities since the amount of cash available for cash distributions would be reduced by the amount of such tax;

(d) The loss of mutual fund trust status would result in the Trust ceasing to be eligible for the capital gains refund mechanism available under the Tax Act; and

(e) Upon the loss of mutual fund trust status, the Trust Units held by Unitholders that are not residents of Canada would become taxable Canadian property. Such Unitholders would be subject to Canadian income tax on any gains realized on a disposition of Trust Units, and to reporting requirements in respect thereof.

For the purpose of maintaining the Trust's status as a "mutual fund trust" under the Tax Act, Provident may, in accordance with the Trust Indenture:

(a) require the Trustee to refuse to accept a subscription for Trust Units from, or issue or register a transfer of Trust Units to, a person unless the person provides a declaration that the Trust Units to be issued or transferred to such person will (when issued or transferred) not be beneficially owned by a non-resident;

(b) to the extent practicable in the circumstances, send a notice to registered holders of Trust Units which are beneficially owned by non-residents, chosen in inverse order to the order of acquisition or registration of such Trust Units beneficially owned by non-residents or in such other manner as Provident may consider equitable and practicable, requiring them to sell their Trust Units which are beneficially owned by non-residents or a specified portion thereof within a specified period of not less than 60 days. If the Unitholders receiving such notice have not sold the specified number of such Trust Units or provided Provident with satisfactory evidence that such Trust Units are not beneficially owned by non-residents within such period, Provident may, on behalf of such registered Unitholder, sell such Trust Units and, in the interim, suspend the voting and distribution rights attached to such Trust Units and make any distribution in respect of such Trust Units by depositing such amount in a separate bank account in a Canadian chartered bank (net of any applicable taxes). Upon such sale, the affected holders shall cease to be holders of Trust Units so disposed of and their rights shall be limited to receiving the net proceeds of sale, and any distribution in respect thereof deposited as aforesaid, net of applicable taxes and costs of sale, upon surrender of the certificates representing such Trust Units;

(c) delist the Trust Units from any non-Canadian stock exchange; and

(d) take such other actions as the board of directors of Provident determines, in its sole discretion, are appropriate in the circumstances that will reduce or limit the number of Trust Units held by non-resident Unitholders to ensure that the Trust is not maintained primarily for the benefit of non-residents.

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Changes in Legislation

There can be no assurance that the treatment of mutual fund trusts will not be changed in a manner which adversely affects Trust Unitholders. If the Trust ceases to qualify as a "mutual fund trust" under the Tax Act, the Trust Units will cease to be qualified investments for registered retirement savings plans, deferred profit sharing plans, registered education savings plans and registered retirement income funds.

Investment Eligibility

The Trust will endeavour to ensure that the Trust Units continue to be qualified investments for Exempt Plans and RESPs. The Tax Act imposes penalties for the acquisition or holding of non-qualified or ineligible investments and there is no assurance that the conditions prescribed for such qualified or eligible investments will be adhered to at any particular time.

Nature of Trust Units

The Trust Units do not represent a traditional investment in the oil and natural gas sector and should not be viewed by investors as shares in Provident. The Trust Units represent a fractional interest in the Trust. The Trust Units will not represent a direct investment in Provident's business. As holders of Trust Units, Trust Unitholders will not have the statutory rights normally associated with ownership of shares of a corporation including, for example, the right to bring "oppression" or "derivative" actions.

The price per Trust Unit is a function of the anticipated Distributable Cash, the oil and gas properties of Provident and Provident's ability to affect long-term growth in the value of the Trust. The market price of the Trust Units will be sensitive to a variety of market conditions including, but not limited to, interest rates and the ability of the Trust to acquire suitable oil and natural gas properties. Changes in market conditions may adversely affect the trading price of the Trust Units.

The Trust Units are not "deposits" within the meaning of the Canada Deposit Insurance Corporation Act (Canada) and are not insured under the provisions of that Act or any other legislation. Furthermore the Trust is not a trust company and, accordingly, it is not registered under any trust and loan company legislation as it does not carry on or intend to carry on the business of a trust company.

Redemption Right

It is anticipated that the redemption right will not be the primary mechanism for Trust Unitholders to liquidate their investments. Notes which may be distributed in specie to Trust Unitholders in connection with a redemption, will not be listed on any stock exchange and no established market is expected to develop for such notes. Cash redemptions are subject to limitations.

Unitholder Limited Liability

The Trust Indenture provides that no Trust Unitholder will be subject to any liability in connection with the Trust or its assets or obligations and, in the event that a court determines that Trust Unitholders are subject to any such liabilities, the liabilities will be enforceable only against, and will be satisfied only out of, the Unitholder's share of the Trust's assets.

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The Trust Indenture provides that all written instruments signed by or on behalf of the Trust must contain a provision to the effect that such obligation will not be binding upon Unitholders personally. Personal liability may also arise in respect of claims against the Trust that do not arise under contracts, including claims in tort, claims for taxes and possibly certain other statutory liabilities. The possibility of any personal liability of this nature arising is considered unlikely.

The operations of the Trust will be conducted, upon the advice of counsel, in such a way and in such jurisdictions as to avoid as far as possible any material risk of liability on the Trust Unitholders for claims against the Trust.

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

Regulatory Matters

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

Conflicts of Interest

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

Competition

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

Dependence on Key Personnel

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

Variations in Interest Rates and Foreign Exchange Rates

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

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

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Statutory Remedies

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

Availability of Credit

As of March 15, 2006, the Trust had drawn $480 million against the Canadian credit facility and had $41 million of the Canadian credit facility drawn on letters of credit, representing 69% of the Canadian credit capacity. In addition, as of March 15, 2006, the Trust had drawn US$48.5 million against the U.S. credit facility and had US$4.4 million of the U.S. credit facility drawn on letters of credit, representing 53% of the U.S. credit capacity. Variations in interest rates and scheduled principal repayments or the need to refinance the credit facility upon expiration could result in significant changes in the amount required to be applied to debt service before payment of any amounts to the Trust. Although it is believed that the credit facilities are sufficient, there can be no assurance that the amounts will be adequate for the financial obligations of the Trust, that additional funds can be obtained or that, upon expiration, the credit facility can be refinanced on terms acceptable to the Trust or the lenders. In such circumstances, cash distributions may be reduced.

INTERESTS OF MANAGEMENT AND OTHERS IN MATERIAL TRANSACTIONS

No director or executive officer of Provident, no person or company that is the direct or indirect beneficial owner of, or who exercises control or direction over more than 10% of the outstanding Trust Units and no associate or affiliate of any of the foregoing persons or companies, has or has had any material interest, direct or indirect, in any transaction within the three most recently completed financial years or during the current financial year that has materially affected or will materially affect the Trust, other than as described in this Annual Information Form.

TRANSFER AGENT AND REGISTRAR

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

INTERESTS OF EXPERTS

As of the date hereof, the principals of McDaniel, independent oil and gas reservoir engineers, as a group, beneficially own, directly or indirectly, less than 1 percent of the Trust Units. As of the date hereof, the principals of NSA, independent oil and gas reservoir engineers, as a group, do not beneficially own, directly or indirectly, any Trust Units. As of the date hereof, the principals of CGA, independent oil and gas reservoir engineers, as a group, beneficially own, directly or indirectly, less than 1 percent of the Trust Units. As of the date hereof, the principals of GLJ, independent oil and gas reservoir engineers, as a group, beneficially own, directly or indirectly, less than 1 percent of the Trust Units.

MATERIAL CONTRACTS

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

DOCUMENTS INCORPORATED BY REFERENCE

Any statement contained in a document incorporated or deemed to be incorporated by reference herein shall be deemed to be modified or superseded for the purposes of this Annual Information Form to the extent that a statement contained herein, or any other subsequently filed document which also is or is deemed to be incorporated by reference herein, modifies or supersedes that statement. The modifying or superseding statement need not state that it has modified or superseded a prior statement or include any other information set forth in the document that is modified or superseded.

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The making of a modifying or superseding statement shall not be deemed an admission for any purposes that the modified or superseded statement, when made, constituted a misrepresentation, an untrue statement of a material fact or an omission to state a material fact that is required to be stated or that is necessary to make a statement not misleading in light of the circumstances in which it was made. Any statement so modified or superseded shall not be deemed, except as so modified or superseded, to constitute a part of this Annual Information Form.

The Trust will provide without charge to each security holder to whom this Annual Information Form is delivered, upon the written or oral request of such person (and to each person who is not a security holder of the Trust upon payment of a reasonable charge), a copy of any or all of the documents incorporated herein by reference, other than exhibits to such documents (unless such exhibits are specifically incorporated by reference into such documents). Requests for such documents should be directed to the office of Investor Relations, Provident Energy Ltd., 800, 112 - 4^th Street S.W., Calgary, Alberta T2P 0H3, telephone: (403) 296-2233. Documents incorporated by reference in this Annual Information Form are also available on SEDAR at www.sedar.com.

PRINCIPAL HOLDERS OF TRUST UNITS

As at the date hereof, to the knowledge of Provident, no person or company owned of record or beneficially, directly or indirectly, more than 10% of the issued and outstanding Trust Units. As at March 21, 2006,the directors and senior officers of Provident, as a group, beneficially owned, directly or indirectly, 2.3 million Trust Units or approximately 1.2%of the issued and outstanding Trust Units and 463,545 Series A exchangeable shares of Provident representing 100% of the issued and outstanding Series A exchangeable shares of Provident. As of March 21, 2006, each such Series A exchangeable share of Provident held by such director or senior officer is exchangeable into Trust Units at an exchange ratio of 1.55621.

ADDITIONAL INFORMATION

Additional information related to the remuneration of the directors and officers of Provident for the year ended December 31, 2005, the indebtedness of the directors and officers of Provident, the principal holders of Trust Units and securities authorized for issuance under equity compensation plans, where applicable, is contained in the Management Proxy Statement and Information Circular of the Trust dated March 29, 2006, which relates to the Annual Meeting of the Unitholders to be held on May 11, 2006. Additional financial information is provided in the Trust's audited consolidated financial statements and management's discussion and analysis for the year ended December 31, 2005.

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

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Laurie Stretch

Investor Relations

Provident Energy Ltd.

800, 112 - 4^th Street S.W.

Calgary, Alberta T2P 0H3

Telephone:(403) 296-2233

Fax:(403) 261-6696

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

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SCHEDULE A

Audit Committee Terms of Reference

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

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

Composition

The Committee will consist of three or more directors as determined by the Board. The members of the Committee shall be appointed by the Board. The Governance, Human Resources and Compensation Committee of the Board shall recommend to the Board eligible directors to fill vacancies on the Committee. Each member shall serve until his or her successor is appointed, unless he shall resign or be removed by the Board or he shall otherwise cease to be a director of the Corporation. The Board shall fill any vacancy if the membership of the Committee is less than three directors. The Chair of the Committee may be designated by the Board or, if it does not do so, the members of the Committee may elect a Chair by vote of a majority of the full Committee membership.

All members of the Committee must satisfy the independence, financial literacy and experience requirements of applicable Canadian and United States securities laws, rules and guidelines, any applicable stock exchange requirements or guidelines and any other applicable regulatory rules. In particular: (i) each member shall be "independent" and "financially literate" within the meaning of Multilateral Instrument 52-110 Audit Committees ("MI 52-110"), (ii) each member shall be "independent" and "financially literate" within the meaning of the rules of the New York Stock Exchange, and (iii) at least one member must be an "audit committee financial expert" within the meaning of that term under the United States Securities Exchange Act of 1934, as amended, and the rules adopted by the United States Securities and Exchange Commission thereunder (collectively, the "U.S. Rules").

Members of the Committee may not, other than in their respective capacities as members of the Committee, the Board or any other committee of the Board, accept directly or indirectly any consulting, advisory or other compensatory fee from Provident, or be an "affiliated person" (as such term is defined in the U.S. Rules) of Provident. For greater certainty, director's fees, options and similar compensation arrangements and fixed amounts of compensation under a retirement plan (including deferred compensation) for prior service with Provident that are not contingent on continued service should be the only compensation a Committee member receives from Provident.

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Communication, Authority to Engage Advisors and Expenses

The Committee shall have access to such officers and employees of the Provident, the external auditor, the independent reserves evaluator(s) and to such other information respecting Provident, as it considers to be necessary or advisable in order to perform its duties and responsibilities.

The Committee provides an avenue for communication, particularly for outside directors, with the external auditor and financial and senior management and the Board. The external auditor shall have a direct line of communication to the Committee through its Chair and shall report directly to the Committee. The Committee, through its Chair, may directly contact any employee of Provident as it deems necessary, and any employee may bring before the Committee, on a confidential basis, any matter involving Provident's financial practices or transactions.

The Committee has the authority to engage independent counsel and other advisors as it determines necessary to carry out its duties and to set the compensation for any such counsel and advisors. Any engagement of independent counsel or other advisors is to be at Provident's expense.

Provident shall be responsible for all expenses of the Committee that are deemed necessary or appropriate by the Committee in carrying out its duties including the compensation of the external auditor for issuing an audit report or performing other audit, review or attest services.

Meetings and Record Keeping

Meetings of the Committee shall be conducted as follows:

1.   the Committee shall meet at least quarterly at such times and at such locations as the Chair of the Committee shall determine, provided that meetings shall be scheduled so as to permit timely review of the Trust's quarterly and annual financial statements and related management's discussion and analysis and earnings press releases. The external auditor or any two members of the Committee may also request a meeting of the Committee. The Committee shall also meet separately with the external auditor and/or internal auditor periodically as the Committee may deem appropriate. The Chair of the Committee shall hold in camera sessions of the Committee, without management present, at every meeting;

2.   the Chair of the Committee shall preside as chair at each Committee meeting and lead Committee discussion on meeting agenda items;

3.   the quorum for meetings shall be a majority of the members of the Committee, present in person or by telephone or by other telecommunication device that permits all persons participating in the meeting to hear each other;

4.   if the Chair of the Committee is not present at any meeting of the Committee, one of the other members of the Committee who is present at the meeting shall be chosen by the Committee to preside at the meeting;

5.   the Chair shall, in consultation with management and the external auditor, establish the agenda for the meetings and instruct management to ensure that properly prepared agenda materials are circulated to the Committee with sufficient time for study prior to the meeting;

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6.   every question at a Committee meeting shall be decided by a majority of the votes cast;

7.   the Chief Executive Officer (the "CEO"), the President and the Chief Financial Officer ("CFO") shall be available to advise the Committee, shall receive notice of meetings and may attend meetings of the Committee at the invitation of the Chair of the Committee. Other management representatives, other Board members, officers or employees of Provident, the external auditor, outside counsel and other experts or consultants may be invited to attend as necessary; and

8.   a Committee member, or any other person selected by the Committee, shall be appointed at each meeting to act as secretary for the purpose of recording the minutes of each meeting.

The Committee shall provide the Board with a summary of all meetings together with a copy of the minutes from such meetings. Where minutes have not yet been prepared, the Chair shall provide the Board with oral reports on the activities of the Committee. Information reviewed and discussed by the Committee at any meeting shall be referred to in the minutes and made available for examination by the Board upon request to the Chair of the Committee.

Responsibilities

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

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

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

Specific Duties

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

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1.   Financial Information and Reporting

(a)   to review with management and the external auditor, and recommend to the Board for approval, the annual and interim financial statements of the Trust and related financial reporting, including management's discussion and analysis and earnings press releases;

(b)   to review and discuss with management the type and presentation of information to be included in press releases which contain financial information taken from Provident's financial statements prior to the release of such press release to the public, paying particular attention to any use of information which is not prepared in accordance with Canadian generally accepted accounting principles ("GAAP"), such as "pro forma" or "adjusted" non-GAAP information, as well as financial information and earnings guidance provided by Provident to analysts and rating agencies;

(c)   to review with management and recommend to the Board for approval, any financial statements of the Trust which have not previously been approved by the Board and which are to be included in a prospectus or other public disclosure document of the Trust;

(d)   to consider and be satisfied that adequate policies and procedures are in place for the review of the Trust's disclosure of financial information extracted or derived from the Trust's financial statements (other than disclosure referred to in clause (1)(a) above), and periodically assess the adequacy of such procedures;

(e)   to review major issues regarding accounting principles and financial statement presentations, including any significant changes in Provident's selection or application of accounting principles;

(f)   to review analyses prepared by management and/or the external auditor setting forth any significant financial reporting issues and judgments made in connection with the preparation of Provident's financial statements, including analyses of the effects of alternative GAAP methods on the financial statements;

(g)   to review the effect of regulatory and accounting initiatives, as well as off-balance sheet structures, on Provident's financial statements;

2.   Internal Controls

(a)   to review the internal control staff functions including:

(i)   the purpose, authority and organizational reporting lines, and

(ii)   the annual audit plan, budget and staffing thereof;

(b)   to review, with the CFO, controller or others, as appropriate, Provident's internal system of audit controls and the results of internal audits;

(c)   to review major issues regarding the adequacy of Provident's internal controls and any special audit steps adopted in light of material control deficiencies;

(d)   to establish procedures for:

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(i)   the receipt, retention and treatment of any complaint regarding accounting, internal accounting controls or auditing matters, and

(ii)   the confidential, anonymous submissions by employees of concerns regarding questionable accounting or auditing matters;

3.   External Audit

(a)   to recommend to the Board the external auditor to be nominated for the purpose of preparing or issuing an auditor's report or performing other audit, review or attest services and the compensation of such auditor;

(b)   to evaluate and oversee the services provided by the external auditor and recommend to the Board, if necessary, the replacement of the external auditor;

(c)  

(i)   to pre-approve or approve (if pre-approval is not required by law) the fees related to, any audit service or non-prohibited non-audit service and, if desired, establish detailed policies and procedures for the pre-approval of audit services and non-prohibited non-audit services by an external auditor. The Committee may delegate this ability to one or more members of the Committee to the extent permitted by applicable law, provided that any pre-approvals granted pursuant to such delegation must be detailed as to the particular service to be provided, may not delegate Committee responsibilities to management of Provident and must be reported to the full Committee at its next scheduled meeting, or

(ii)   adopt specific policies and procedures for the engagement of the external auditor for the purposes of the provision of non-audit services;

(d)   to obtain and review at least annually a written report by the external auditor setting out the auditor's internal quality control procedures, any material issues raised by the auditor's internal quality control reviews, or by inquiry or investigation by governmental or professional authorities within the preceding five years, respecting one or more independent audits carried out by the firm and the steps taken to resolve those issues;

(e)   to review and discuss with the external auditor all relationships that the external auditor and its affiliates have with Provident in order to determine the external auditor's independence, including, without limitation:

(i)   requesting, receiving and reviewing, on a periodic basis but at least annually, a formal written statement from the external auditor delineating all relationships that may reasonably be thought to bear on the independence of the external auditor with respect to Provident,

(ii)   discussing with the external auditor any disclosed relationships or services that the external auditor believes may affect the objectivity and independence of the external auditor, and

(iii)   recommending that the Board take appropriate action in response to the external auditor's report to satisfy itself of the external auditor's independence at least annually, obtain and review a report by the external auditor describing: the firm's internal quality control procedures; any material issues raised by the most recent internal quality control review, or peer review, of the firm, or by any inquiry or investigation by governmental or professional authorities, within the preceding five years, respecting one or more independent audits carried out by a firm, and any steps taken to deal with any such issues;

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(f)   to review the audit plan of the external auditor prior to the commencement of the audit;

(g)   to set clear hiring policies for Provident regarding partners and employees and former partners and employees of the present and former external auditor of the Trust;

(h)   to obtain assurance from the external auditor that disclosure to the Committee is not required pursuant to the provisions of the United States Securities Exchange Act of 1934, as amended, regarding the discovery of any illegal acts by the external auditor;

(i)   to review with the external auditor any audit problems or difficulties, including any restrictions on the scope of the external auditor's activities or on access to requested information, any significant disagreements with management, and management's response (such review should also include discussion of the responsibilities, budget and staffing of Provident's internal audit function, if any);

(j)   to review and discuss a report from the external auditor at least quarterly regarding:

(i)   all critical accounting policies and practices to be used,

(ii)   all alternative treatments within generally accepted accounting principles for policies and practices related to material items that have been discussed with management, including the ramifications of the use of such alternative disclosures and treatments, and the treatment preferred by the external auditor,

(iii)   other material written communications between the external auditor and management, such as any management letter or schedule of unadjusted differences, and

(iv)   to present its conclusions with respect to the external auditor to the full Board;

(k)   the Committee will ensure the rotation of partners on the audit engagement team of the external auditor in accordance with applicable law. The Committee will also periodically consider whether, in order to assure continuing external auditor independence, it is appropriate to adopt a policy of rotating the external auditing firm on a regular basis;

(l)   the Committee will review and evaluate the lead partner of the external auditor;

4.   Risk Management

(a)   to review and monitor Provident's major financial risks and risk management policies and the steps taken by management to monitor and control those risks;

(b)   at the request of the Board, review transactions or matters which could materially affect the financial profile of the Trust;

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(c)   the Committee shall, at least annually, provide a review of the Corporation's directors and officers liability insurance to the board.

5.   Compliance and Review of CEO and CFO Certification Process

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

(b)   in connection with its review of the annual audited financial statements and interim financial statements, the Committee will also review the process for the CEO and CFO certifications with respect to the financial statements and Provident's disclosure and internal controls, including any material deficiencies or changes in those controls. The Committee will review with the CEO, the CFO and the external auditor: (i) all significant deficiencies and material weaknesses in the design or operation of Provident's internal control over financial reporting which could adversely affect Provident's ability to record, process, summarize and report financial information required to be disclosed by the Trust in the reports that it files or submits under the United States Securities Exchange Act of 1934, as amended, within the required time periods, and (ii) any fraud, whether or not material, that involves management of Provident or other employees who have a significant role in Provident's internal control over financial reporting.

Other Matters

1.   The Committee shall review and reassess the adequacy of this mandate at least annually and otherwise as it deems appropriate and recommend changes to the Board.

2.   The performance of the Committee shall be evaluated annually by the Board against criteria defined in the Committee and Board mandates.

3.   The Committee may, at the request of the Board or on its own initiative, investigate such other matters as it considers necessary or appropriate in the circumstances, including, without limitation, matters relating to corporate governance, compensation and director nominations.

4.   The Committee may delegate its responsibilities to sub-committees of the Committee.

APPENDIX A

AUDIT COMMITTEE ANNUAL CALENDAR

(December 31 year end)

Quarterly Audit Committee Meetings: May, August and November

·Approval of quarterly financial statements such as:

MD&A;

press release;

estimates and management judgments; and

Review of report from external auditor.

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

·Other standard items including management reporting on:

Material communication with rating agencies;

Material legal matters/litigation; and

Analyst reports.

· Report from Audit Committee Chair on pre-approvals for audit, non-audit, review or attestation assignments.

·In camera review with external auditor.

February or March Meeting to Review Audited Financial Statements

·Review annual financial statements, MD&A and related disclosure.

·Discuss significant accounting policies.

·Discuss critical estimates, and judgments and impact on statements.

·Review business risks disclosure in MD&A.

· Receive external auditor's report on statutory audit and various matters where external auditor is required to report, such as:

auditor independence;

methods used to account for significant unusual transactions;

material proposed audit adjustments and immaterial adjustments not recorded by management;

auditor judgments about the quality of the Company's accounting principles;

management-related issues encountered in performing the audit; and

disagreements with management over the application of accounting principles, management's accounting estimates and related matters.

· Review management's "internal control report" to be included in annual report and external auditor's assessment of same.

· Internal control issues, if any.

· Separate in camera meetings with the external auditor and external counsel.

· Annual information form and comparable 40-F and 20-F.

· Public disclosure relevant to Audit Committee, such as re-appointment of auditor, disclosure of pre-approval procedures as required by SEC Auditor Independence Rules and disclosure relating to financial experts.

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October/November Meeting

· Discuss annual audit plan including scope of engagement and related matters such as:

audit team and potential rotation;

review and consideration of budgeted audit fees; and

special areas for concentration by external audit.

· Review preparations for production of "internal control report" for annual report.

· Review Audit Committee charter and report to Board.

· Review and affirmation of principles for pre-approval of audit, non-audit, review and attestation services.

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

·Educational component to Audit Committee functions such as:

critical accounting policies/estimates/general discussion;

treasury activities;

internal control risks;

support to CEO/CFO certification;

financing vehicles, loan documents and applicable covenant patterns;

taxation issues and tax planning;

new developments such as:

- non-GAAP earnings measures; and

- identification of financial experts;

competitors and accounting issues involving competitors;

preparing of Audit Committee effectiveness report for Board of Directors;

business risks and related oversight responsibilities of Audit Committee including applicable procedures; and

earnings guides such as:

- pro forma reporting; and

- selective disclosure policy.

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

· Communication with the Corporate Governance Committee as may be required.

· Review of complaints received and outcome of investigation.

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

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2005 Year-end and Fourth Quarter Results

Management’s discussion and analysis

The following analysis provides a detailed explanation of Provident’s operating results for the quarter and year ended December 31, 2005 compared to the quarter and year ended December 31, 2004 and should be read in conjunction with the consolidated financial statements of Provident. This analysis has been prepared using information available up to March 10, 2006.

Provident Energy Trust has diversified investments in certain segments of the energy value chain. Provident currently operates in three key business segments: Canadian crude oil and natural gas production and exploitation (“COGP”), United States crude oil and natural gas production and exploitation, (“USOGP”) and midstream services and marketing (“Midstream”). Provident’s “COGP” business produces crude oil and natural gas from five core areas in the western Canadian sedimentary basin. USOGP produces crude oil and natural gas in the Los Angeles and Santa Maria basins in California and in Wyoming. The Midstream business unit operates in Canada and the U.S.A. and extracts, processes, markets, transports and offers storage of natural gas liquids within the integrated facilities at Younger in British Columbia, Redwater, Empress, and Kerrobert in Saskatchewan, Sarnia in Ontario, Superior in Wisconsin and Lynchburg in Virginia.

This analysis commences with a summary of the consolidated financial and operating results followed by segmented reporting on the COGP business unit, the USOGP business unit and the Midstream business unit. The reporting focuses on the financial and operating measurements management uses in making business decisions and evaluating performance.

Forward-looking statements

Certain statements included in this analysis constitute forward-looking statements under applicablesecurities legislation. These statements relate to future events or Provident’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. Forward-looking statements or information in this analysis include, but are not limited to, business strategy and objectives, reserve quantities and the discounted present value of future net cash flows from such reserves, net revenue, future production levels, capital expenditures, exploration plans, development plans, acquisition and disposition plans and the timing thereof, operating and other costs, royalty rates, budgeted levels of cash distributions and the performance associated with Provident's natural gas midstream, NGL processing and marketing business. These statements are only predictions. Actual events or results may differ materially. In addition, this analysis 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. In addition to other assumptions identified in this analysis, assumptions in respect of forward-looking statements have been made regarding, among other things:

o   Provident’s ability to benefit from the combination of growth opportunities and the ability to grow through the capital markets;

o   Provident’s acquisition strategy, the criteria to be considered in connection therewith and the benefits to be derived therefrom;

o   the sustainability and growth of production and reserves through prudent management and acquisitions;

o   the emergence of accretive growth opportunities;

o   the ability to achieve a consistent level of monthly cash distributions;

o   the impact of Canadian governmental regulation on Provident;

o   the existence, operation and strategy of the commodity price risk management program;

o   the approximate and maximum amount of forward sales and hedging to be employed;

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

o   the level of capital expenditures devoted to development activity rather than exploration;

o   the sale, farming out or development using third party resources to exploit or produce certain exploration properties;

o   the use of development activity and acquisitions to replace and add to reserves;

o   the quantity of oil and natural gas reserves and oil and natural gas production levels;

o   currency, exchange and interest rates;

o   the performance characteristics of Provident's natural gas midstream, NGL processing and marketing business;

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

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

1

Although Provident 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. Provident can not guarantee future results, levels of activity, performance, or achievements. Moreover, neither the Trust, Provident 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 Provident's control, which could cause results to differ materially from those expressed in the forward-looking statements contained in this analysis include, but are not limited to:

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

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

o   uncertainties associated with estimating reserves;

o   royalties payable in respect of oil and gas production;

o   governmental regulation of the oil and gas industry, including income tax and environmental regulation;

o   fluctuation in foreign exchange or interest rates;

o   stock market volatility and market valuations;

o   the impact of environmental events;

o   the need to obtain required approvals from regulatory authorities;

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

o   failure to obtain industry partner and other third party consents and approvals, when required; and

o   third party performance of obligations under contractual arrangements.

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 analysis are expressly qualified by this cautionary statement. Subject to Provident’s obligations under applicable securities laws, Provident is not under any duty to update any of the forward-looking statements after the date of this analysis to conform such statements to actual results or to changes in Provident’s expectations.

2

Consolidated financial highlights

	Quarter ended December 31,					Year ended December 31,
($ 000s except per unit data)
		2005		2004 (1)	% Change		2005		2004 (1)	% Change
Revenue (net of royalties and financial derivative instruments)	$	442,687	$	369,435	20	$	1,360,274	$	1,109,857	23
Cash flow from COGP operations	$	51,992	$	30,273	72	$	185,129	$	121,144	53
Cash flow from USOGP operations		16,014		11,525	39		59,821		21,458	179
Cash flow from midstream services and marketing		28,292		16,573	71		66,238		42,644	55
Total cash flow from operations	$	96,298	$	58,371	65	$	311,188	$	185,246	68
Per weighted average unit - basic (2)	$	0.57	$	0.41	39	$	1.95	$	1.63	20
Per weighted average unit - diluted (3)	$	0.51	$	0.40	28	$	1.95	$	1.63	20
Declared distributions to unitholders	$	62,646	$	52,064	20	$	230,714	$	164,628	40
Per unit (2)	$	0.36	$	0.36	-	$	1.44	$	1.44	-
Percent of cash flow from operations paid out as declared distributions		65%		89%	(27)		74%		89%	(17)
Net income	$	54,501	$	38,314	42	$	96,926	$	21,225	357
Per weighted average unit - basic (2)	$	0.32	$	0.27	19	$	0.61	$	0.19	221
Per weighted average unit - diluted (3)	$	0.32	$	0.27	19	$	0.61	$	0.19	221
Capital expenditures	$	51,011	$	26,471	93	$	156,499	$	76,321	105
Midstream NGL acquisition	$	772,303		-	-	$	772,303		-	-
Nautilus acquisition	$	-	$	-	-	$	91,420	$	-	-
Property acquisitions	$	(94)	$	64,036	(100)	$	586	$	72,745	(99)
Property dispositions	$	461	$	6,603	(93)	$	45,100	$	13,717	229
Weighted average trust units outstanding (000s)
- Basic(2)		169,609		141,273	20		159,316		113,310	41
- Diluted(3)		188,036		144,922	30		159,686		113,489	41

		As at December 31,
($ 000s)		2005		2004	% Change
Long-term debt	$	884,604	$	432,206	105
Unitholders’ equity	$	1,404,826	$	1,009,048	39
(1) Restated for the impact of the retroactive implementation of the change in accounting policies for exchangeable securities - non-controlling interest - see note 3
(2) Excludes exchangeable shares
(3) Includes dilutive impact of unit options, exchangeable shares and convertible debentures.

3

Operational highlights

	Quarter ended December 31,					Year Ended December 31,
(000s except per unit amounts)
COGP and USOGP combined		2005		2004	% Change		2005		2004	% Change
Oil and Gas Production
Daily production
Light/medium crude oil (bpd)		14,051		14,012	-		14,979		10,146	48
Heavy oil (bpd)		3,195		6,536	(51)		4,358		6,608	(34)
Natural gas liquids (bpd)		1,653		1,770	(7)		1,596		1,494	7
Natural gas (mcfpd)		73,363		87,339	(16)		77,095		77,022	-
Oil equivalent (boed)(1)		31,126		36,874	(16)		33,782		31,085	9
Average selling price (before hedges)
Light/medium crude oil ($/bbl)	$	55.31	$	45.83	21	$	54.69	$	45.01	22
Heavy oil ($/bbl)	$	28.62	$	25.33	13	$	31.33	$	28.72	9
Corporate oil blend ($/bbl)	$	50.36	$	39.31	28	$	49.43	$	38.59	28
Natural gas liquids ($/bbl)	$	49.44	$	42.80	16	$	49.09	$	40.68	21
Natural gas ($/mcf)	$	11.44	$	6.56	74	$	8.43	$	6.60	28
Oil equivalent ($/boe)(1)	$	57.50	$	39.50	46	$	49.86	$	39.12	27
Field netback (before hedges) ($/boe)	$	34.63	$	22.33	55	$	29.97	$	22.18	35
Field netback (including hedges) ($/boe)	$	28.33	$	16.58	71	$	24.73	$	16.31	52
Midstream services and marketing
Managed volumes (bpd)		77,100		52,870	46		64,740		57,484	13
EBITDA (000s)(2)	$	29,566	$	17,957	65	$	70,689	$	50,085	41
(1) Provident reports oil equivalent production converting natural gas to oil on a 6:1 basis.
(2) EBITDA is earnings before interest , taxes, depletion, depreciation, accretion and other non-cash items.

4

Fourth quarter highlights

The fourth quarter highlights section provides commentary on the fourth quarter 2005 results compared to the fourth quarter of 2004. Definitions of terms used in this section, as appropriate, are defined in the year over year section of the Management’s Discussion and Analysis following later in this press release.

Consolidated cash flow from operations and cash distributions

		Three months ended December 31,
($ 000s, except per unit data)			2005		2004	% Change
Revenue, Cash Flow and Distributions
Revenue (net of royalties and financial derivative instruments)		$	442,687	$	369,435	20
Cash flow from operations before changes in working capital and site restoration		$	96,298	$	58,371	65
	Per weighted average unit - basic (1)	$	0.57	$	0.41	39
	Per weighted average unit - diluted (2)	$	0.51	$	0.40	28
Declared distributions		$	62,646	$	52,064	20
	Per Unit (1)		0.36		0.36	-
Percent of cash flow distributed			65%		89%	(27)
(1) Excludes exchangeable shares
(2) Includes the dilutive impact of unit options, exchangeable shares and convertible debentures.

Fourth quarter 2005 cash flow was $96.3 million, 65 percent above the $58.4 million of cash flow recorded in the fourth quarter of 2004. COGP 2005 fourth quarter cash flow was $52.0 million, 72 percent above the $30.3 million recorded in the comparable 2004 quarter. The main drivers for the COGP increase were the 27 percent increase in realized crude oil and natural gas liquids prices and the 75 percent increase in realized natural gas prices partially offset by the 26 percent reduction in production that reflects the 2,100 boed September 2005 property disposition and production declines partially offset by incremental production added through capital expenditures. The Midstream business unit added $28.3 million to fourth quarter 2005 cash flow, 71 percent above the $16.6 million recorded in the comparable 2004 quarter. About half of this increase is attributable to the Midstream NGL Acquisition, with the remainder the result of increased product premiums in 2005 over 2004. Cash flow from operations in USOGP increased 39 percent to $16.0 million driven by a 51 percent increase in production volumes compared to cash flow of $11.5 million in the comparable 2004 quarter.

Declared distributions in the fourth quarter of 2005 totaled $62.6 million, 65 percent of cash flow from operations. This compares to $52.1 million of declared distributions in 2004, 89 percent of cash flow from operations.

Net Income

	Three months ended December 31,
($ 000s, except per unit data)		2005		2004 (3)	% Change
				(Restated)
Net income (loss)	$	54,501	$	38,314	42
Per weighted average unit - basic(1)		0.32		0.27	19
Per weighted average unit - diluted(2)		0.32		0.27	19
(1) Based on weighted average number of trust units outstanding
(2) Based on weighted average number of trust units outstanding including the dilutive impact of the unit option plan, exchangeable shares and convertible debentures.
(3) Restated - note 3

5

Net income for the fourth quarter of 2005 increased 42 percent to $54.5 million compared to a $38.3 million of net income in the comparable 2004 quarter. The fourth quarter earnings reflect the impact of higher commodity prices in COGP, higher production in USOGP as well as significant income generated from the Midstream business unit.

The COGP business segment contributed $34.9 million of net income, $8.8 million above 2004 fourth quarter income of $26.1 million. The increase in the fourth quarter of 2005 reflects increased EBITDA due to higher crude oil and natural gas prices, partially offset by natural production declines and an increased future income tax charge of $5.0 million compared to a $12.6 million recovery in the fourth quarter of 2004.

The Midstream unit contributed $24.1 million of net income in the fourth quarter of 2005, as compared to the $10.8 million of net income in the fourth quarter of 2004. The increase reflects higher product premiums in 2005 and the impact of the Midstream NGL Acquisition.

USOGP incurred a net loss of $4.5 million in the fourth quarter of 2005 with a comparative net income of $1.4 million for 2004. The decrease in the fourth quarter of 2005 reflects an increased future income tax charge of $18.3 million, which more than offsets higher pre-tax income due to an increase in production resulting from the acquisition of the Nautilus properties combined with unrealized gains on financial derivatives in the fourth quarter of 2005.

Comparative figures for fourth quarter 2004 net income have been restated to reflect the retroactive application of changes in accounting policy for exchangeable shares - non-controlling interest that resulted in a reduction to net income of $0.9 million.

Taxes

	Three months ended December 31,
($ 000s)		2005		2004	% Change
Capital taxes	$	1,103	$	2,547	(57)
Current and withholding taxes (recovery)		(1,296)		664	(295)
Future income tax expense (recovery)		23,327		(10,000)	333
	$	23,134	$	(6,789)	441

Capital taxes in the fourth quarter totaled $1.1 million, a decrease of $1.4million from the $2.5 million recorded in the fourth quarter of 2004. The decrease reflects an adjustment for the legislated phase-out of the large corporations tax, netted against the increase in the Saskatchewan resource surcharge that is sensitive to crude oil prices.

The current and withholding tax recovery is $1.3million in the fourth quarter of 2005 with a comparative expense of $0.7 million in the fourth quarter of 2004. These taxes arise from Provident’s U.S. based operations. The recovery in the quarter was due to the immediate deductibility of capital expenditures for income tax purposes of drilling expenditures incurred in the quarter.

The 2005 fourth quarter future tax expense of $23.3 million compares to a $10.0 million future tax recovery in the fourth quarter of 2004. The future tax expense in the fourth quarter of 2005 resulted from changes to estimated tax pools in both Canada and the U.S.A., partially offset by increases in estimated royalty and interest charges by the Trust to subsidiaries which reduced estimated tax pool claims.

Reconciliation of non-GAAP measure

The Trust calculates earnings before interest, taxes, depletion, depreciation and accretion and other non-cash items (EBITDA) within its segment disclosure. EBITDA is a non-GAAP measure. A reconciliation between EBITDA and income before taxes and non-controlling interests follows:

6

	Three months ended December 31,
EBITDA Reconciliation
($ 000s)		2005		2004
EBITDA	$	103,542	$	68,455
Adjusted for:
Interest and non-cash expenses excluding unrealized gain on financial instruments		(56,828)		(60,921)
Unrealized gain on financial instruments		31,943		25,083
Income before taxes and non-controlling interests	$	78,657	$	32,617

Interest Expense

	Three months ended December 31,
($ 000s)		2005		2004	% Change
Interest on bank debt	$	4,100	$	3,365	22
Interest on debentures		3,651		3,981	(8)
Total cash interest		7,751		7,346	6
Non -cash accretion expense - convertible debentures		(752)		(1,165)	(35)
Total interest including accretion on convertible debentures	$	6,999	$	6,181	13

Cash interest expense increased for the quarter as compared to the same quarter in 2004 due to the increase in the overall size of Provident, with commensurate increases in debt levels.

Commodity Price Risk Management Program (CPRMP)

The Trust continues to execute a commodity price risk management program that is designed to limit the Trust’s exposure to downturns in commodity prices and to protect monthly cash distributions. Our hedging strategy uses structures that provide a floor price while allowing upside participation in a rising price market.

In accordance with the Trust’s credit policy, the Trust mitigates associated credit risk by limiting financial derivative transactions to counterparties with investment grade credit ratings and obtaining financial guarantees from certain counterparties.

7

Activity in the Fourth Quarter:

The following is a summary of the net cash flow to settle Commodity contracts during the fourth quarter of 2005. For comparative purposes, the 2004 amounts are also summarized.

a) Crude oil

For the quarter ending December 31, 2005, Provident paid $16.5 million to settle various oil market based contracts on an aggregate volume of 0.6 million barrels. For comparison, during the quarter ending December 31, 2004, Provident paid $16.5 million to settle various oil market based contracts on an aggregate volume of 1.4 million barrels. As at December 31, 2005 the estimated value of contracts in place if settled at December 31 market prices would have resulted in an opportunity cost of $7.1 million (2004 - $25.2 million).

b) Natural Gas

For the quarter ending December 31, 2005, Provident paid $4.1 million to settle various natural gas market based contracts on an aggregate volume of 1.5 million gj’s. For comparison, during the quarter ending December 31, 2004, Provident paid $2.0 million to settle various natural gas market based contracts on an aggregate volume of 8.4 million gj’s. As at December 31, 2005 the estimated value of contracts in place if settled at December 31 market prices would have resulted in an opportunity cost of $6.5 million (2004 - opportunity gain of $0.3 million).

c) Midstream

For the quarter ending December 31, 2005 Provident paid $1.7 million (2004 - $0.3 million gain) on midstream margin stabilization hedging activities. As at December 31, 2005 the estimated value of contracts in place settled at December 31 market prices would have resulted in an opportunity cost of $0.4 million (2004 - opportunity gain of $0.2 million).

d) Foreign exchange contracts

As at December 31, 2005 the estimated value of contracts in place settled at December 31 foreign exchange rates would have resulted in an opportunity cost of $ 0.1 million (2004 - opportunity gain of $0.2 million). The foreign exchange gains have been included as a component of foreign exchange gain and other and allocated to their respective business segments.

Provident’s Commodity Price Risk Management Program is also discussed in the year over year section of Management’s Discussion and Analysis and in Note 17 to the consolidated financial statements.

8

COGP segment review

Crude Oil Price

The following prices are net of transportation expense.

COGP	Three months ended December 31,
($ per bbl)		2005		2004	% Change
WTI (US$)	$	60.02	$	48.27	24
Exchange rate (from US$ to Cdn$)	$	1.17	$	1.21	(3)
WTI expressed in Cdn$	$	70.22	$	58.41	20
Corporate realized crude oil and natural gas liquids price before hedging (Cdn$)	$	45.44	$	35.86	27
Corporate realized light/medium oil price before hedging (Cdn$)	$	52.28	$	42.00	24
Corporate realized heavy oil price before hedging (Cdn$)	$	28.62	$	25.33	13
Corporate realized natural gas liquids price before hedging (Cdn)	$	49.62	$	42.66	16

In the fourth quarter of 2005 COGP’s realized oil and natural gas liquids price, prior to the impact of hedging, increased by 27 percent to $45.44 per barrel compared to $35.86 in the fourth quarter of 2004. The 2005 increase related to a higher US$ WTI crude oil price and lower conventional heavy oil volumes as a percentage of total mix, partially offset by a stronger Canadian dollar and wider differentials on heavy oil pricing relative to WTI.

Natural gas price

The following prices are net of transportation expense.

COGP
	Three months ended December 31,
($ per mcf)		2005		2004	% Change
AECO (Cdn$) per mcf	$	11.67	$	7.07	65
Gas revenue per mcf before hedging(Cdn$)	$	11.40	$	6.53	75

COGP’s fourth quarter 2005 realized natural gas price, prior to the impact of hedging, increased 75 percent as compared to the fourth quarter of 2004, higher than the increase in the benchmark AECO index price of 65 percent. Provident markets to aggregators and sells to the spot market on monthly or daily indices and receives prices which take into account heat content. Provident’s realized prices and changes in prices are therefore different than benchmark indices.

Production

	Three months ended December 31,
COGP
	2005	2004	% Change
Daily production
Crude oil - Light/Medium (bpd)	6,866	9,281	(26)
- Heavy (bpd)	3,195	6,536	(51)
Natural gas liquids (bpd)	1,617	1,746	(7)
Natural gas (mcfd)	71,168	85,803	(17)
Oil equivalent (boed) (1)	23,539	31,864	(26)
(1) Provident reports equivalent production converting natural gas to oil on a 6:1 basis.

Production decreased 26 percent to 23,539 boed during the fourth quarter of 2005 as compared to 31,864 boed in 2004. The decrease reflects the September 29, 2005 disposition of various non-core properties that averaged approximately 2,100 boed and the natural production declines including higher than expected declines in heavy oil

9

partially offset by drilling and optimization activities. Production declines in COGP’s heavy oil areas in excess of what was expected were mainly attributable to one field with declines in the other fields consistent with similar type of properties. Provident’s production risk is mitigated by not having any single property providing greater than 10 percent of its total production.

Production for the fourth quarter of 2005 was weighted 50 percent natural gas, 36 percent medium/light crude oil and natural gas liquids and 14 percent heavy oil. This compared to fourth quarter 2004 production weighted 45 percent natural gas, 35 percent medium/light oil and natural gas liquids and 21 percent heavy oil. Quarter-over-quarter, the change in mix reflects increased capital spending on natural gas opportunities, natural production declines and the 2,100 boed September 2005 property disposition that included approximately 1,010 boed of heavy oil, which typically has a lower netback than the other commodities.

COGP’s production summarized by core areas is as follows:

COGP
Three months ended December 31, 2005	West Central Alberta	Southern Alberta	Southern Saskatchewan	Lloydminister	Other	Total
Daily production
Crude oil - Light/Medium (bpd)	1,057	2,541	2,063	1,204	1	6,866
- Heavy (bpd)	-	-	-	3,195	-	3,195
Natural gas liquids (bpd)	1,418	179	1	19	-	1,617
Natural gas (mcfd)	38,343	22,722	9,112	978	13	71,168
Oil equivalent (boed) (1)	8,865	6,507	3,583	4,581	3	23,539

COGP
Three months ended December 31, 2004	West Central Alberta	Southern Alberta	Southern Saskatchewan	Lloydminister	Other	Total
Daily production
Crude oil - Light/Medium (bpd)	1,395	3,069	3,012	1,787	18	9,281
- Heavy (bpd)	-	-	-	6,536	-	6,536
Natural gas liquids (bpd)	1,576	142	-	22	6	1,746
Natural gas (mcfd)	47,705	27,967	4,314	5,030	787	85,803
Oil equivalent (boed) (1)	10,922	7,872	3,731	9,184	155	31,864
(1) Provident reports equivalent production converting natural gas to oil on a 6:1 basis.

Internal development activities included 40.7 net wells drilled during the quarter ended December 31, 2005. Provident’s most active area, southern Saskatchewan realized 24.1 net wells drilled focused on a shallow gas-drilling program that will realize production and reserve adds for several years. Poor weather conditions in south Saskatchewan delayed tie-in operations at the beginning of the third quarter of 2005 so these wells continued to be brought on production in the fourth quarter of 2005. Provident’s other core areas remain active with additional activity in southern Alberta where Provident is actively drilling in shallow gas wells and in Lloydminster where Provident is drilling low risk heavy oil wells. In West Central Alberta, Provident continues with its strategy of farming out high risk exploration land to generate cash flow with minimal or no capital outlay.

10

Revenue and royalties

Revenue figures are presented net of transportation expense.

COGP
	Three months ended December 31,
($ 000s except per boe and mcf data)		2005		2004	% Change
Oil
Revenue	$	41,440	$	50,282	(18)
Realized loss on non-hedging derivative instruments		(11,651)		(16,511)	(29)
Royalties (net of ARTC)		(8,969)		(10,230)	(12)
Net revenue	$	20,820	$	23,541	(12)
Net revenue (per barrel)	$	22.49	$	16.18	39
Royalties as a percentage of revenue		21.6%		20.3%
Natural gas
Revenue	$	74,623	$	51,637	45
Realized loss on non-hedging derivative instruments		(1,521)		(2,001)	(24)
Royalties (net of ARTC)		(15,503)		(11,107)	40
Net revenue	$	57,599	$	38,529	49
Net revenue (per mcf)	$	8.80	$	4.95	78
Royalties as a percentage of revenue		20.8%		21.5%
Natural gas liquids
Revenue	$	7,382	$	6,852	8
Royalties		(2,013)		(1,464)	38
Net revenue	$	5,369	$	5,388	-
Net revenue (per barrel)	$	36.09	$	33.54	8
Royalties as a percentage of revenue		27.3%		21.4%
Total
Revenue	$	123,445	$	108,771	13
Realized loss on non-hedging derivative instruments		(13,172)		(18,512)	(29)
Royalties (net of ARTC)		(26,485)		(22,801)	16
Net revenue	$	83,788	$	67,458	24
Net revenue per boe	$	38.69	$	23.01	68
Royalties as a percentage of revenue		21.5%		21.0%

Quarter-over-quarter, 2005 COGP production revenue was $123.4 million, an increase of 13 percent from $108.8 million in 2004. The increase in revenue is a result of a 27 percent increase in Provident’s realized crude oil and natural gas liquids price and a 75 percent increase Provident’s realized natural gas prices offset by lower production. Total royalties as a percentage of revenue remained relatively constant at 21-22 percent. The preceding factors, as well as the decrease in opportunity cost of hedging activities, account for net revenue of $83.8 million in the fourth quarter of 2005, 24 percent above the $67.5 million recorded in the fourth quarter of 2004. Net revenue per boe in the fourth quarter of 2005 was $38.69 per boe, an increase of 68 percent from $23.01 per boe in the fourth quarter of 2004. The increase is a result of an increase in natural gas production to 50 percent of total mix combined with the increase in realized prices.

11

Production expenses

COGP	Three months ended December 31,
($ 000s, except per boe data)		2005		2004	% Change
Production expenses	$	23,437	$	26,431	(11)
Production expenses (per boe)	$	10.82	$	9.02	20

Fourth quarter 2005 production expenses decreased 11 percent to $23.4 million from $26.4 million in the comparable 2004 quarter due to lower production volumes. On a boe basis quarter over quarter production expenses have risen to $10.82 per boe, a 20 percent increase from $9.02 per boe in the comparable 2004 quarter. Cost increases in power and fuel, chemicals, well servicing, maintenance and fluid hauling reflect higher commodities prices and labour costs and combined with the lower production volumes result in higher operating costs per boe.

Operating netback

COGP	Three months ended December 31,
($ per boe)		2005		2004	% Change
COGP oil equivalent netback per boe
Gross production revenue	$	57.00	$	37.10	54
Royalties (net of ARTC)		(12.23)		(7.78)	57
Operating costs		(10.82)		(9.02)	20
Field operating netback	$	33.95	$	20.30	67
Realized loss on non-hedging derivative instruments		(6.08)		(6.31)	(4)
Operating netback after non-hedging derivative instruments	$	27.87	$	13.99	99

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

The fourth quarter 2005 field operating netback of $33.95 per boe was 67 percent above the $20.30 per boe in the comparable quarter in 2004. This reflects COGP’s higher realized prices for both natural gas and crude oil and natural gas liquids. These prices combined with a shift in COGP’s production mix to include more high netback natural gas and less low netback heavy oil results in a significant improvement in the field operating netback. Reflected in the shift in the production mix is the September 2005 disposition of 2,100 boed of low netback non-core properties. Royalties, which are price sensitive, increased by 57 percent on a boe basis reflecting the higher prices, prior to the impact of hedging. The fourth quarter 2005 operating netback after hedging increased by 99 percent to $27.87 from $13.99 reflecting the explanation above as well as lower 2005 fourth quarter hedging opportunity costs of $6.08per boe compared to $6.31 in the comparable quarter in 2004.

General and administrative

The following table does not incorporate the COGP portion of non-cash unit based compensation expenses associated with Provident’s unit option plan and restricted and performance unit plan. Fourth quarter non-cash unit based compensation expenses for COGP totaled $1.9 million compared to $0.2 million recovery in the comparable period.

COGP		Three months ended December 31,
($ 000s, except per boe data)		2005		2004	% Change
Cash general and administrative	$	3,727	$	3,918	(5)
Cash general and administrative per boe	$	1.72	$	1.34	28

12

Cash general and administrative expenses for COGP in the fourth quarter decreased 5 percent to $3.7million from $3.9 million recorded in the 2004 comparable quarter. On a boe basis the cash general and administrative expenses recorded in fourth quarter 2005 increased 28 percent to $1.72 from $1.34 in the fourth quarter of 2004. The increase in general and administrative expenses reflects additional costs associated with a more competitive landscape affecting the cost of hiring and compensating employees and consultants, as well as increases in rent, insurance and compliance and reporting costs.

COGP operations are capable of absorbing additional production, particularly in existing core areas, with little impact on general and administrative expenses. 2006 costs per boe are forecasted to increase as a result of further increases in costs associated with compliance (including costs associated with the implementation of procedures and documentation to be in compliance with the U.S. Sarbanes-Oxley Act) and a more competitive landscape impacting the cost of hiring and compensating employees.

Capital expenditures

COGP
	Three months ended December 31,
($ 000s)		2005		2004
West central and southern Alberta	$	7,259	$	8,413
Southeast and southwest Saskatchewan		11,931		8,201
Lloydminster		2,497		4,799
Office and other		(13)		185
Total additions	$	21,674	$	21,598
Property acquisitions		(94)		413
Property dispositions	$	461	$	6,603

In the fourth quarter of 2005, Provident’s COGP business unit spent $21.7 million on capital expenditures. In the southeast and southwest Saskatchewan core areas $11.9 million was spent on shallow gas drilling and carrying out several recompletions ($6.6 million). Facility work ($5.3 million) in the area focused on infrastructure to tie-in future shallow gas production in southwest Saskatchewan. In southern Alberta $5.0 million was spent on drilling activities and recompletions ($3.3 million) and facility upgrades ($1.6 million). In the Lloydminster core area $2.5 million was spent primarily on drilling ($1.5 million) and facility work ($0.9 million) and in West central Alberta $2.3 million was spent largely on non-operated drilling ($0.6 million) and facility work ($1.6 million).

Provident’s COGP business unit spent $21.6 million in the fourth quarter of 2004 on various drilling, re-completing, optimization and facility projects.

Depletion, depreciation and accretion (DD&A)

COGP	Three months ended December 31,
($ 000s, except per boe data)			2005		2004
DD&A		$	33,809	$	45,315
DD&A per boe		$	15.61	$	15.46

COGP DD&A rate of $15.61 per boe remained relatively flat for the fourth quarter of 2005 compared to $ 15.46 per boe for the fourth quarter of 2004. Accretion expense associated with asset retirement obligations was $0.5 million in the fourth quarter of 2005 compared to $0.6 million in the fourth quarter of 2004. The decrease is mainly a result of the non-core property disposition in the third quarter of 2005.

13

USOGP Segment Review

The USOGP business unit incorporates activities from Provident’s subsidiary, Breitburn Energy LP (Breitburn), an oil and gas exploitation and production business based in Los Angeles, California.

On March 2, 2005 Breitburn acquired Nautilus Resources, LLC, a U.S. private company with operations focused in the Big Horn and Wind River basins of Wyoming for cash consideration of $90.2 million and acquisition costs of $1.2 million.

USOGP Pricing

USOGP	Three month ended December 31,
		2005		2004	% Change
USOGP realized crude oil and natural gas liquids price before hedging (Cdn$ per bbl)	$	58.11	$	53.34	9
Natural Gas (Cdn$ per mcf)		12.97		8.02	62

The majority of USOGP oil production is light, sweet crude that attracts smaller differentials to benchmark prices relative to heavier blends. Realized prices before hedging increased by nine percent while WTI increased by 24 percent in the fourth quarter of 2005 compared with the fourth quarter of 2004. This was due to production and revenue from the acquired Wyoming properties being included in 2005 average prices. Oil production from the Wyoming properties is a heavier blend of crude oil that attracts wider differentials from WTI pricing, and generate approximately 20 percent less revenue per boe than Southern California operations. Production in Wyoming represents approximately 30 percent of fourth quarter 2005 production.

Production

	Three month ended December 31,
USOGP		2005	2004	% Change
Daily production - by product
Crude oil - Light/Medium (bpd)		7,185	4,730	52
Natural gas liquids (bpd)		36	24	50
Natural gas (mcfd)		2,195	1,536	43
Oil equivalent (boed) (1)		7,587	5,010	51
(1) Provident reports equivalent production converting natural gas to oil on a 6:1 basis.

	Three month ended December 31,
USOGP		2005	2004	% Change
Daily Production - by area (boed) (1)
Los Angeles		3,974	3,558	12
Santa Maria		1,356	1,364	(1)
Wyoming		2,257	88	2,465
		7,587	5,010	51
(1) Provident reports equivalent production converting natural gas to oil on a 6:1 basis.

USOGP production increased 2,577 boe per day or 51 percent in the fourth quarter of 2005 when compared to the fourth quarter of 2004. The increase in Los Angeles production is a result of successful drilling and optimization activities. The Wyoming increase is primarily attributable to the addition of the Nautilus properties on March 2, 2005.

14

Revenue and royalties

The following table outlines USOGP revenue and royalties by product line. The table excludes revenues earned from operating certain properties ($0.3million in 2005 and $0.3 million in 2004) on behalf of third parties.

USOGP	Three month ended December 31,
($ 000s, except per boe and mcf amounts)	2005			2004	% Change
Oil
Revenue	$	38,583	$	23,212	66
Realized loss on non-hedging derivative instrument		(4,875)		(81)	5,919
Royalties		(3,703)		(2,041)	81
Net revenue	$	30,005	$	21,090	42
Net revenue (per bbl)	$	45.39	$	48.46	(6)
Royalties as a percentage of revenue		9.6%		8.8%
Natural gas
Revenue	$	2,620	$	1,134	131
Royalties		(370)		-	-
Net revenue	$	2,250	$	1,134	98
Net revenue (per mcf)	$	11.14	$	6.56	70
Royalties as a percentage of revenue		14.1%		0.0%
Natural gas liquids
Revenue	$	135	$	118	14
Royalties		(3)		-	-
Net revenue	$	132	$	118	12
Net revenue (per bbl)	$	40.06	$	52.23	(23)
Royalties as a percentage of revenue		2.1%		0.0%
Total
Revenue	$	41,338	$	24,464	69
Realized loss on non-hedging derivative instrument		(4,875)		(81)	5,919
Royalties		(4,076)		(2,041)	100
Net revenue	$	32,387	$	22,342	45
Net revenue (per boe)	$	46.40	$	48.47	(4)
Royalties as a percentage of revenue		9.9%		8.3%

Total production revenue for the fourth quarter of 2005 was $41.3 million or 69 percent higher than the $24.5 million of revenue in the fourth quarter of 2004. The increase was primarily driven by higher commodity prices combined with revenues from the Wyoming properties acquired in the first quarter of 2005. Total net revenue increased $10.1 million or 45 percent in the fourth quarter of 2005 compared to the fourth quarter of 2004. The increase was driven by higher commodity prices combined with the revenues from the acquired Wyoming properties offset by increases in realized losses on non-hedging derivative instruments. The increase in royalties as a percentage of revenue is primarily driven by the addition of the acquired Wyoming properties as these properties have, on average, higher royalty rates than Southern California production.

15

Production expenses

USOGP	Three months ended December 31,
($ 000s, except per boe amounts)		2005		2004	% Change
Production expenses	$	11,510	$	6,989	65
Production expenses (per boe)	$	16.49	$	15.16	9

Production expenses increased 65 percent to $11.5 million in the fourth quarter of 2005 compared to $7.0 million for the comparable quarter in 2004. This increase is due to the 51 percent increase in production volumes and higher costs on a boe basis. Operating costs per boe have increased nine percent to $16.49 in the fourth quarter of 2005 from $15.16 in the comparable quarter in 2004. This change reflects both the increase in utilities and other costs and servicesdriven by the high commodity price environment as well as higher operating cost crude oil wells that were returned to production to take advantage of high crude oil prices. Increases in production expense per boe were tempered by expenses from acquired properties in Wyoming. Wyoming production expenses are, on average, 20 percent lower than production expenses incurred in the Southern California operations.

General and administrative

USOGP	Three months ended December 31,
($ 000s, except per boe amounts)		2005		2004	% Change
Cash general and administrative	$	4,525	$	2,264	100
Cash general and administrative (per boe)	$	6.48	$	4.91	32

Cash general and administrative expenses in the fourth quarter at $4.5million or $6.48per boe is a 32 percent increase from the fourth quarter of 2004. The increase is primarily associated with an increase in personnel combined with an increased in short-term incentive plans to attract and retain personnel in a highly competitive environment.

Operating netback

USOGP	Three months ended December 31,
($ per boe)		2005	2004		% Change
Netback
Gross production revenue	$	59.22	$	53.08	12
Royalties		(5.84)		(4.43)	32
Operating costs		(16.49)		(15.16)	9
Field Operating Netback	$	36.89	$	33.49	10
Non-hedging derivative instruments		(6.98)		(0.18)	3,778
Operating netback after non-hedging derivative instruments	$	29.91	$	33.31	(10)

The operating netback for the fourth quarter of 2005 remains strong driven by high commodity prices partially offset by increased operating costs. The fourth quarter 2005 operating netback of $29.91 per boe is 10 percent lower than the $33.31 per boe due to the increased hedge losses incurred by USOGP operations. The majority of the hedges entered into in 2005, however, lapsed on December 31, 2005.

16

Income taxes and cash taxes

USOGP	Three months ended December 31,
($ 000s)		2005		2004	% Change
Capital, current and withholding taxes	$	(1,296)	$	853	(252)
Future income tax expense		18,320		-	-
	$	17,024	$	853	1896

Current and withholding taxes include current U.S. federal and state income taxes as well as accrued or paid U.S. withholding taxes on payments that have been or will be made from Breitburn Energy LP to Provident. The recovery in the quarter was due to the immediate deductibility of capital expenditures for income tax purposes of drilling expenditures incurred in the quarter. The 2005 future income tax expense resulted from deduction of drilling costs for tax purposes in 2005 which are capitalized for accounting purposes and from changes to estimated tax pools.

Capital expenditures

USOGP capital expenditures for the fourth quarter of 2005 totaled $11.5 million. Of this total, $7.0 million was directed at drilling, optimization and facility upgrades at West Pico, Santa Fe Springs and Orcutt. $2.5 million was directed at drilling and optimization work in Wyoming, while $2.0 million was directed at optimization projects at smaller fields as well as head office related capital expenditures.

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

17

Midstream services and marketing segment review

The Midstream services and marketing business segment extracts, processes, stores, transports and markets natural gas liquids (NGL’s) across integrated assets in British Columbia, Alberta, Ontario and the United States.

NGL Acquisition

On December 13, 2005 Provident acquired NGL assets and the Kinetic marketing entity from EnCana Corporation (Midstream NGL Acquisition) for $772.3 million, net of cash acquired, including $38.9 million of working capital that includes $85.5 million of inventory. The assets acquired are described in the year over year MD&A section. The fourth quarter results incorporate the results of operations associated with these Midstream assets since acquisition.

Operations - managed NGL volumes

Midstream managed approximately 77,100 bpd of NGL’s over the fourth quarter and closed the year with managed NGL volumes of approximately 140,640 bpd. This reflects enhanced operations of the Redwater facilities as well as the addition of the newly acquired Empress/Sarnia assets and NGL marketing. NGL product managed in the fourth quarter of 2004 was 52,870 bpd.

Product sales and service revenues

For the fourth quarter of 2005 product sales and services revenues were $295.6 million, compared to $251.9 million in the fourth quarter of 2004. The fourth quarter of 2005 includes $67.2 million in product sales and services revenue associated with the Midstream NGL Acquisition. Excluding this additional amount, revenue declined by $23.5 million when compared to the fourth quarter of 2004. The reduction in revenue is due to the sale of certain crude oil marketing contracts on May 1, 2005 partially offset by higher product prices. Revenue figures are after elimination of intersegment transactions and include product sales related to transportation and fractionation (T&F), extraction, processing and marketing, additional fee for service revenues generated through storage and distribution services, and for the 2004 comparative quarter crude oil sales generated through oil marketing activities.

Cost of goods sold

The cost of goods sold was $245.0 million for the fourth quarter of 2005 compared to $221.6 million in the fourth quarter of 2004. The fourth quarter of 2005 includes $58.1 million in cost of goods sold associated with the Midstream NGL Acquisition. Excluding this additional amount, the cost of goods sold declined by $34.7 million when compared to the fourth quarter of 2004. This reduction in cost of goods sold is due to the sale of certain crude oil marketing contracts on May 1, 2005 offset by higher product prices. These figures are after elimination of intersegment transactions and relate to NGL product sales revenue included in the product sales and services revenue, where Provident has purchased natural gas liquids and for the comparative 2004 quarter for oil purchased pursuant to oil marketing activities. The NGL costs would be applicable to the T&F and marketing contracts and a small percentage of volume delivered from the Younger facility on which Provident manages extraction economics.

Product margin

Product margin is the revenue less the cost of good sold and is representative of the margins obtained on marketed products, however it is affected by fee for service revenues that are grouped in with product sales and service revenues. In the fourth quarter of 2005, $50.6 million or a 17 percent product margin was generated on $295.6 million of product sales and service revenues compared to $30.3 million or a 12 percent product margin generated on $251.9 million of 2004 fourth quarter product sales and service revenues. The 2005 fourth quarter product margin would be expected to be higher than the comparable fourth quarter of 2004 which included the lower margin crude oil marketing activities. In future quarters the product margin will be subject to a wider range of variability driven by the Midstream NGL Acquisition that increases exposure to extraction economics.

18

Fractionation Spread Support Program

As part of the Midstream NGL Acquisition the vendor provided a fractionation support agreement that is more fully described in the 2005 year over year Management’s Discussion and Analysis section. The impact of the agreement on the fourth quarter of 2005 was a receipt of $5.2 million that resulted in a reduction in the cost of goods available for sale with no comparative for the fourth quarter of 2004.

Other expenses

Fourth quarter 2005 operating costs of $11.7 million (2004 - $10.1 million) represent normal operations and includes end December operating costs for the Empress/Sarnia system as well as the Redwater assets. General and administrative expenses were $5.8 million for the fourth quarter 2005 (2004 - $2.5 million). Increases in general and administrative expenses in the fourth quarter of 2005 as compared to 2004 resulted from allocation of costs and increased direct costs resulting from the Midstream NGL Acquisition which was negotiated, announced and closed in the fourth quarter 2005. Depreciation expense was $4.2 million for the three months ended December 31, 2005 (2004 - $2.8 million).

Earnings before interest, taxes, depletion, depreciation, accretion, and other non-cash items (“EBITDA”)and cash flow from operations

The fourth quarter of 2005 results for the Midstream services and marketing business unit reflected in EBITDA, cash flow and net income benefited from efficient operations, marketing opportunities, increased revenues associated with storage and distribution services, the fractionation support agreement and 19 days of operating activities for the NGL Acquisition. Fourth quarter 2005 EBITDA of $29.6 million increased 64 percent from $18.0 million in the year ago quarter. Cash flow for the fourth quarter of 2005 quarter was $28.3 million 71 percent above the $16.6 million for the fourth quarter 2004. About half of this increase is attributable to the Midstream NGL Acquisition with the remainder the result of increased product premiums in 2005 over 2004. Fourth quarter net income at $24.1 million was 123 percent above the $10.8 million of net income recorded in the fourth quarter of 2004.

Management uses EBITDA to analyze the operating performance of the Midstream business unit. EBITDA as presented does not have any standardized meaning prescribed by Canadian GAAP and therefore it may not be comparable with the calculation of similar measures for other entities. EBITDA as presented is not intended to represent operating cash flow or operating profits for the period nor should it be viewed as an alternative to cash flow from operating activities, net earnings or other measures of financial performance calculated in accordance with Canadian GAAP. All references to EBITDA throughout this report are based on Earnings before interest, taxes, depletion, depreciation, accretion, and other non-cash items (“EBITDA”).

Capital expenditures

Midstream capital expenditures, excluding corporate acquisitions, for the fourth quarter of 2005 totaled $16.5 million. Included in this was $15.5 million of growth capital spent on new product handling facilities including the new condensate offloading and terminalling facilities announced in October 2005 as well as truck loading and a rail yard expansion. The remaining capital was spent on pipelines and in the Younger extraction plant. Capital spending amounted to $1.2 million in the fourth quarter of 2004.

19

2005 Year end results

Consolidated cash flow from operations and cash distributions

		Year ended December 31,
($ 000s, except per unit data)			2005		2004	% Change
					(Restated)
Revenue, Cash Flow and Distributions
Revenue (net of royalties and financial derivative instruments - see Note 9 to the consolidated financial statements)		$	1,360,274	$	1,109,857	23
Cash flow from operations before changes in working capital and site restoration expenditures		$	311,188	$	185,246	68
	Per weighted average unit - basic (1)	$	1.95	$	1.63	20
	Per weighted average unit - diluted (2)	$	1.95	$	1.63	20
Declared distributions		$	230,714	$	164,628	40
	Per Unit (1)		1.44		1.44	-
Percent of cash flow distributed			74%		89%	(17)
(1) Excludes exchangeable shares
(2) Includes dilutive impact of unit options, exchangeable shares and convertible debentures.

For the year ended December 31, 2005, cash flow increased 68 percent or $126.0 million to $311.2 million from $185.2 million for 2004 (per unit in 2005 - $1.95; 2004 - $1.63). COGP generated $185.1 million, USOGP $59.8 million, and Midstream $66.3 million of cash flow during 2005. During 2004 COGP generated cash flow of $121.1 million, USOGP $21.5 million, and Midstream $42.6 million.

Canadian oil and gas operations contributed $64.0 million of the cash flow increase, a result of a 23 percent increase in realized crude oil and natural gas liquids price and a 28 percent increase in realized natural gas prices, offset by 8 percent lower production due to natural declines and a September property disposition of 2,100 boed outweighing incremental production adds brought on through capital expenditures. The U.S. oil and gas operations provided increased cash flow of $38.3 million in 2005, compared to 2004, representing a full year of production in 2005 from the U.S. operations that were acquired on June 15, 2004, as well as the contribution of the Nautilus properties, acquired in March of 2005. The Midstream segment accounted for $23.7 million of the increase in cash flow reflecting the marketing opportunity afforded by selling NGL’s into a rising market, increased fee for service revenues for storage and distribution and a $6.2 million contribution from 19 days of operations from the Midstream NGL Acquisition.

Declared distributions in 2005 totaled $ 230.7 million, 74 percent of cash flow from operations. This compares to $164.6 million of declared distributions in 2004, 89 percent of cash flow from operations. Provident’s objective is to provide stable distributions to its unitholders. Distributions for 2006 are budgeted to be maintained at their current level.

Management uses cash flow (before changes in non-cash working capital and site restoration expenditures) to analyze operating performance. Provident also reviews cash flow in setting monthly distributions and takes into account cash required for debt repayment and/or capital programs in establishing the amount to be distributed. Historically Provident has paid out between 74 percent and 102 percent of its annual cash flow as distributions to unitholders.

Cash flow as presented does not have any standardized meaning prescribed by Canadian generally accepted accounting principles (GAAP) and therefore it may not be comparable with the calculation of similar measures for other entities. Cash flow as presented is not intended to represent operating cash flow or operating profits for the period nor should it be viewed as an alternative to cash flow from operating activities, net earnings or other measures of financial performance calculated in accordance with Canadian GAAP. All references to cash flow throughout this report are based on cash flow before changes in non-cash working capital and site restoration expenditures.

20

Distributions

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

			Distribution Amount
Record Date	Payment Date		(Cdn$)	(US$)*
2005
January 20, 2005	February 15, 2005	$	0.12	0.10
February 18, 2005	March 15, 2005		0.12	0.10
March 21, 2005	April 15, 2005		0.12	0.10
April 20, 2005	May 13, 2005		0.12	0.10
May 19, 2005	June 15, 2005		0.12	0.10
June 20, 2005	July 15, 2005		0.12	0.10
July 20, 2005	August 15, 2005		0.12	0.10
August 19, 2005	September 15, 2005		0.12	0.10
September 20, 2005	October 14, 2005		0.12	0.10
October 21, 2005	November 15, 2005		0.12	0.10
November 21, 2005	December 15, 2005		0.12	0.10
December 20, 2005	January 13, 2006		0.12	0.10
2005 Cash Distributions paid as declared		$	1.44	1.20
2004 Cash Distributions paid as declared			1.44	1.10
2003 Cash Distributions paid as declared			2.06	1.47
2002 Cash Distributions paid as declared			2.03	1.29
2001 Cash Distributions paid as declared - March 2001 - December 2001			2.54	1.64
Inception to December 31, 2005 - Distributions paid as declared		$	9.51	6.70
*exchange rate based on the Bank of Canada noon rate on the payment date.

For Canadian tax purposes, 2005 distributions were determined to be 76.5 percent taxable and 23.5 percent a tax-deferred return of capital in the hands of Canadian unitholders. The 2004 comparables were 71 percent and 29 percent respectively. Distributions received by U.S. resident unitholders in 2005 are classified as 94.4 percent qualified dividend and 5.6 percent tax deferred return of capital. The 2004 comparables were 83 percent and 17 percent respectively. In both Canada and the U.S., the tax-deferred portion would usually be treated as an adjustment to the cost base of the units. Unitholders or potential unitholders should consult their own legal or tax advisors as to their particular income tax consequences of holding Provident units.

Net Income

Year ended December 31,
($ 000s, except per unit data)		2005		2004 (3)	% Change
				(Restated)
Net income (loss)	$	96,926	$	21,225	357
Per weighted average unit - basic(1)		0.61		0.19	221
Per weighted average unit - diluted(2)		0.61		0.19	221

⁽¹⁾ Based on weighted average number of trust units outstanding

⁽²⁾ Based on weighted average number of trust units outstanding including the dilutive impact of the unit option plan, exchangeable shares and convertible debentures.

⁽³⁾ Restated - note 3.

21

Year ended December 31,
($ 000s)		2005		2004	% Change
				(Restated)
COGP net income (loss)	$	35,352	$	(20,059)	276
USOGP net income		5,422		9,482	(43)
Total oil and gas net income		40,774		(10,577)	485
Midstream net income		56,152		31,802	77
Net Income	$	96,926	$	21,225	357

For the year ended December 31, 2005, consolidated earnings of $96.9 million resulted from oil and gas net income of $40.8 million and Midstream net income of $56.1 million.

The combined net income for COGP and USOGP of $41.8 million for 2005 compares to a loss of $10.6 million in 2004. Higher commodity prices in Canada and the United States combined with a full year of production in the U.S. resulted in a 66 percent improvement in earnings before interest, taxes, depletion, depreciation, and accretion and other non-cash items. Also, in 2004 Provident recorded a non-cash revenue reduction of $22.4 million in its oil and gas operations, largely due to the implementation of CICA Accounting Guideline 13, “Hedging relationships”. The comparable figure for 2005 was a revenue increase of $9.2 million, resulting mainly from unrealized gains on financial derivative instruments. The Midstream segment contributed $56.1million of net income in 2005, a 77 percent increase over 2004. The increase is due to higher product premiums in 2005 as well as an increase in product prices over the period.

Taxes

Year ended December 31,
($ 000s)		2005		2004	% Change
Capital taxes	$	4,780	$	5,921	(19)
Current and withholding taxes		5,628		1,282	339
Future income tax expense (recovery)		17,793		(40,577)	144
	$	28,201	$	(33,374)	184

Future income taxes arise as a result of the difference between the accounting and tax bases of the operating companies and subsidiaries. Payments to the Trust by these subsidiaries are deductible for income taxes. The Trust is a taxable entity under the Income Tax Act (Canada) and is taxable only on income that is not distributed or distributable to the unitholders. As the Trust distributes all of its taxable income to the unitholders and meets the requirements of the Income Tax Act (Canada) applicable to the Trust, no provision for income taxes has been made in the Trust.

Capital taxes include the Saskatchewan Resource surcharge and federal and provincial large corporation taxes. Current and withholding taxes reflect U.S. taxes that are incurred on operations associated with Provident’s June 15, 2004 acquisition of U.S. based BreitBurn Energy. U.S. operations are subject to U.S. federal and state income taxes. Payments from U.S. entities to Canadian entities are subject to withholding taxes if the distributions are characterized by U.S. tax authorities as dividends or interest.

The 2005 future income tax expense of $17.8 million compares to a $40.6 million recovery for the comparable 2004 period. The future tax expense in 2005 resulted from changes to estimated tax pools in both Canada and the U.S.A, partially offset by increases in estimated royalty and interest charges by the Trust to subsidiaries which reduced estimated tax pool claims.

Reconciliation of non-GAAP measure

The Trust calculates earnings before interest, taxes, depletion, depreciation and accretion, and other non-cash items (EBITDA) within its segment disclosure. EBITDA is a non-GAAP measure. A reconciliation between EBITDA and income (loss) before taxes and non-controlling interests follows:

22

EBITDA Reconciliation	Year ended December 31,
($ 000s)		2005		2004	% Change
EBITDA	$	349,181	$	218,065	60
Adjusted for:
Interest and non-cash expenses excluding unrealized gain/(loss) on financial instruments		(229,372)		(206,781)	11
Unrealized gain/(loss) on financial instruments		7,684		(22,053)	135
Income (loss) before taxes and non- controlling interests	$	127,493	$	(10,769)	1,294

Interest expense

Year ended December 31,
($ 000s, except as noted)		2005		2004	% Change
Interest on bank debt	$	10,875	$	11,816	(8)
Weighted-average interest rate on bank debt		3.85%		3.96%	(3)
Interest on 10.5% convertible debentures(3)		1,682		5,226	(68)
Interest on 8.75% convertible debentures		4,923		6,421	(23)
Interest on 8.0% convertible debentures (1)		3,577		2,153	66
Interest on 6.5% convertible debentures (2)		5,393		-	-
Interest on 6.5% convertible debentures (4)		1,219		-	-
Total cash interest	$	27,669	$	25,616	8
Weighted average interest rate on all long-term debt		4.91%		6.05%	(19)
Non -cash accretion expense - convertible debentures		2,849		1,373	108
Total interest including accretion on convertible debentures	$	30,518	$	26,989	13

⁽¹⁾ On July 6, 2004 the Trust issued $50.0 million of unsecured subordinated convertible debentures with an 8 percent coupon rate maturing July 31, 2009.

⁽²⁾ On March 1, 2005 the Trust issued $100.0 million of unsecured subordinated convertible debentures with a 6.5 percent coupon rate maturing August 31, 2012.

⁽³⁾ On May 31, 2005 the Trust redeemed the 10.5 percent unsecured subordinated convertible debentures issuing 3.5 million trust units and $3.0 million in cash.

⁽⁴⁾ On November 15, 2005 the Trust issued $150.0 million of unsecured subordinated convertible debentures with a 6.5 percent coupon rate maturing April 30, 2011.

Interest expense increases for the year reflect increased debt levels as a result of corporate growth. Cash interest expense on debentures increased in 2005 as compared to 2004 reflecting the March 1, 2005 issue of $100.0 million of 6.5 percent subordinated convertible debentures and the November 15, 2005 issue of $150.0 million of 6.5 percent subordinated convertible debentures partly offset by $63.6 million of debenture conversions and the May 31 redemption of approximately $45.7 million of 10.5 percent subordinated convertible debentures. Accretion and amortization on convertible debentures has resulted from Provident adopting in 2004 the revised CICA Handbook section 3860 and reclassifying the bulk of its subordinated convertible debentures to long-term debt and an additional portion to equity.

Financial instruments

Commodity price risk management program

For the year ended December 31, 2005 $66.9 million was recorded as realized loss on financial derivative instruments due to the Commodity Price Risk Management Program (the Program) with $64.6 million related to the combined oil and gas operations and $2.3 million associated with the Midstream segment.

23

In the oil and gas business units the hedging cost associated with crude oil totaled $59.0 million ($8.36 per barrel) and $5.6 million related to natural gas ($0.19 per gj). The combined total was $64.6 million or $5.24per boe. In 2004 the Program recorded an opportunity cost of $65.7 million or $5.78per boe with $55.3 million related to crude oil ($9.03 per barrel) and $10.4 million related to natural gas ($0.35 per gj).

In 2005 the Midstream segment recorded a hedging cost of $2.3 million primarily on propane and ethane price stabilization and frac-spread margin hedging activities. In 2004 the Program recorded a cost of $3.2 million for these activities.

Realized gains on foreign exchange contracts which fixed the exchange rates on foreign currency contracts related to the Program have been presented as a component of foreign exchange gain and other and allocated to their respective business segments.

On a per trust unit basis the opportunity cost of the Program decreased to $0.42 per trust unit in 2005 from $0.61 per trust unit in 2004.

At December 31, 2005 the mark to market value of open contracts was in a loss position of $14.1 million based upon commodity prices prevailing at that date. This amount has been reflected in the financial statements of the Trust pursuant to Accounting Guideline 13 and Emerging Issues Committee Abstract 128 in respect of accounting for financial instruments.

Provident’s Commodity Price Risk Management Program involves a disciplined hedging strategy that utilizes dervivative instruments to provide for insurance against lower commodity prices, protect against price volatility, secure bank financing, improve debt coverage and assist with more predictable and stable cash distributions. The hedging strategy protects a percentage of production against a decline in commodity prices while, with some products, allowing the Trust to participate in a rising commodity price environment. It provides price stabilization and protection of inventory values and fractionation spread margin associated with the midstream services and marketing business units. As well, the Provident hedging stategy reduces foreign exchange risk due to the exposure arising from the conversion of U.S. dollars into Canadian dollars.

Provident will continue to execute the Program in 2006. The derivative instruments the Trust uses include puts, calls, costless collars, participating swaps, fixed and indexed referenced pricing.

Disclosure Controls and Procedures

Based on the requirements of Multilateral Instrument 52-109 of the Canadian Securities Administrators, management evaluated the effectiveness of Provident’s disclosure controls and procedures. Based on that evaluation, management concluded that Provident’s disclosure controls and procedures were effective as of December 31, 2005.

Acquisitions

Provident completed two major acquisitions during 2005. On March 2, 2005 Provident acquired Nautilus Resources, LLC (Nautilus) for cash consideration of $90.2 million and acquisition costs of $1.2 million. Nautilus was a private oil and gas exploration and production business active in Wyoming, U.S.A. The acquisition added $99.9 million to property plant and equipment. Other asset and liability accounts were also assigned values. The transaction has been accounted for using the purchase method.

On December 13, 2005 Provident acquired midstream business assets (the Midstream NGL Acquisition) by way of the purchase of partnership interests, corporations and assets for $772.3 million (net of cash acquired and including acquisition costs). The business is comprised of NGL extraction plants, pipelines, storage and fractionation facilities, distribution facilities, contracts including supply and transportation arrangements, and ownership of Kinetic, partnerships which perform NGL marketing services including Kinetic’s interests in a distribution terminal and leases on approximately 700 rail cars. The transaction was accounted for using the purchase method. The purchase added $428.1 million to property, plant and equipment; $217.0 million to intangible assets; and $98.1 million to goodwill.

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The Midstream NGL Acquisition was financed by the issuance of 21,830,000 units at $12.60 per unit and $150.0 million of 6.5 percent convertible unsecured subordinated debentures. The remaining portion of the purchase price of the Midstream NGL Acquisition was funded through Provident’s credit facility.

Dispositions

On May 1, 2005 Provident sold the crude oil purchase and sale contracts that underpinned its crude oil marketing business. Net proceeds were $5.5 million and the gain net of disposal cost was $5.2 million.

On September 29, 2005, Provident, disposed of various non-core properties and land in Saskatchewan and Alberta for cash proceeds, net of disposition costs, of $44.6 million. The net cash proceeds were initially applied to debt and will mainly be used to fund Provident’s ongoing budgeted capital program. The disposed properties averaged approximately 2,100 boed for the period July 1, 2005 to September 28, 2005 and included approximately 1,010 boed of heavy oil. Proved plus probable reserves totaled 6,397 mboe and approximately 87,850 net acres of undeveloped land were also included. The disposition resulted in a $13.6 million reduction to Provident’s future asset retirement obligation, which represented the discounted future cash flows to settle the asset retirement obligations related to these properties. Under full cost accounting rules, unless the disposed oil and gas assets result in a greater than 20 percent impact on the depletion rate, no gain or loss is recognized.

On December 29, 2005 the USOGP business unit disposed of a parcel of land in California for net proceeds of $23.8 million and recorded a deferred gain of $1.0 million.

Goodwill

Goodwill representsthe excess of the cost of an acquired enterprise over the net of the amounts assigned to assets acquired and liabilities assumed, goodwill arose from the acquisitions of Richland Petroleum Corporation, $13.3 million, and Meota Resources Corp., $89.1 million in 2002 and from Olympia Energy Inc., $106.5 million, and Viracocha Energy Inc., $122.0 million in 2004. In 2005, the Midstream NGL Acquisition resulted in additional goodwill of $98.1 million.

Goodwill is assessed for impairment at least annually, and if an impairment exists, it would be charged to income in the period in which the impairment occurs. Provident engaged an independent accounting firm to assist in performing an impairment test at year end. The impairment test includes, amongst other variables, a comparison of the net book value of the Trust’s assets to the market value of the Trust’s equity. Goodwill is not amortized.

Liquidity and capital resources

December 31,
($ 000s)		2005		2004	% Change
Long-term debt - revolving term credit facility	$	586,597	$	262,750	123
Long-term debt - convertible debentures		298,007		169,456	76
Working capital deficit		-		38,677	(100)
Net debt		884,604		470,883	88
Equity (at book value)		1,404,826		1,009,048	39
Total capitalization at book value	$	2,289,430	$	1,479,931	55
Net debt as a percentage of total book value capitalization		39%		32%	22

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

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Long-term debt and working capital

As at December 31, 2005 Provident had drawn on 68 percent of its term credit facilities of $750 million and USD $100 million as compared to 64 percent drawn on its $410.0 million term credit facility as at December 31, 2004. The increase in the level of bank debt was due to the increase scale of operations primarily due to acquisitions. The increased percentage of the credit facilities drawn reflects the Midstream NGL Acquisition that closed on December 13, 2005.

At December 31, 2005 Provident had letters of credit guaranteeing Provident’s performance under certain commercial and other contracts that totaled $45.1 million, increasing bank line utilization to 73 percent. The guarantees at December 31, 2004 totaled $31 million.

Provident’s working capital increased by $113.1 million from a deficit of $38.7 million to a surplus of $74.4 million as at December 31, 2005. Of this increase $7.7 million was due to unrealized hedging gains, a $93.5 million increase in petroleum product inventory, of which $85.6 million was added by the Midstream NGL Acquisition, and a $5.2 million increase in declared distributions payable while the balance was due to changes in other accounts reflecting the increased scale of activities including capital activities.

Fourth quarter cash flow in 2005 was $96.3 million. The ratio of debt to annualized fourth quarter cash flow was 2.30 to one, as compared to fourth quarter annualized debt to cash flow in 2004 of 1.85 to one. The 2005 annualized and fourth quarter debt to cash flow ratios are skewed upward as the debt reflects the full purchase price of the Midstream NGL Acquisition of $772.3 million but only 19 days of cash flow from the acquired assets.

Trust units and exchangeable shares

On March 1, 2005 the Trust issued 8.4 million units at a price of $12.00 per unit for proceeds after underwriting fees of $95.6 million, concurrent with the issue of convertible debentures noted above. Proceeds from the issue were used to pay down Provident’s bank debt and to finance the Nautilus Resources, LLC acquisition and throughout 2005 was used to finance the company’s 2005 capital budget. In 2005, the Trust also issued 2.9 million units (conversion amount $28.4 million) on conversion of exchangeable shares to units (2004 - 1.6 million units; conversion amount $15.3 million) and 9.6 million units on conversion and redemption of convertible debentures (2004 - 11,378 units). An additional 2.3 million units pursuant to the stock option plan were issued in 2005 (2004 - 0.6 million units). Details of these issues are outlined in the notes to the financial statements. Under Provident’s Premium Distribution, Distribution Reinvestment (DRIP) and Optional Unit Purchase Plan program 1.4 million units were elected in 2005 and will be issued or are to be issued representing proceeds of $18.4 million (2004 - 1.9 million units for proceeds of $19.9 million).

On November 15, 2005 the Trust issued 21.83 million Subscription Receipts at a price of $12.60 per Subscription Receipt for total proceeds of $275.1 million ($261.0 million net of issue costs). Each Subscription Receipt entitled the holder to receive one trust unit upon completion of the Midstream NGL Acquisition. The acquisition closed on December 13, 2005 at which time all of the outstanding Subscription Receipts were converted to trust units. At that time, the holders of the Subscription Receipts were also entitled to $0.12 per trust unit, which is the equivalent of the November distribution paid in December. This payment was treated as a reduction to the purchase price of the units acquired through the Subscription Receipts to $12.48 per trust unit, reducing the amount attributed to Unitholders’ contributions by $2.6 million. Proceeds from the issue were used to fund the Midstream NGL Acquisition.

At December 31, 2005 management and directors held approximately 1.2 percent of the outstanding units and exchangeable shares.

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Non-Controlling Interest

 (i)   USOGP operations

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

	Year ended December 31,
Non-controlling interest USOGP ($ 000s)		2005		2004
Opening non-controlling interest, beginning of year	$	13,649	$	13,690
Net income attributable to non-controlling interest		1,596		923
Distributions to non-controlling interest holders		(3,360)		(964)
Closing non-controlling interest, end of period		11,885		13,649
Accumulated income attributable to non-controlling interest	$	2,519	$	923

Additional investments by Provident in BreitBurn Energy LP have reduced the non-controlling interest percentage at December 31, 2005 to approximately 4.4 percent.

 (ii)   Exchangeable shares

As at June 30, 2005 the Trust retroactively applied EIC-151 “Exchangeable Securities Issued by a Subsidiary of an Income Trust”. The non-controlling interest on the consolidated balance sheet consists of the fair value of the exchangeable shares upon issuance plus the accumulated earnings attributable to the non-controlling interest. The net income attributable to the non-controlling interest on the consolidated statement of operations represents the cumulative share of net income attributable to the non-controlling interest based on the trust units issuable for exchangeable shares in proportion to total trust units issued and issuable at each quarter end during the year.

Following is a summary of the non-controlling interest - exchangeable shares for the years ended December 31, 2005 and 2004:

		Year ended December 31,
Non-controlling interest - Exchangeable shares ($ 000s)		2005		2004 (1)
Non-controlling interest, beginning of period	$	35,921	$	20,543
Exchangeable shares issued		-		30,264
Reduction of book value for conversion to trust units		(28,432)		(15,343)
Net income attributable to non-controlling interest		770		457
Non-controlling interest, end of period	$	8,259	$	35,921
Accumulated income attributable to non-controlling interest	$	2,252	$	1,482
(1) Restated - note 3.

The non-controlling interest percentage as at December 31, 2005 was 0.6 percent that is a decrease from the retroactively applied non-controlling interest percentage as at December 31, 2004 of 2.2 percent. The decrease is attributable to the conversion of exchangeable shares for trust units and the increase in trust units from other issuances.

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Capital Expenditures and Funding

Year ended December 31,
($ 000s)		2005		2004	% Change
Capital Expenditures and Funding
Capital Expenditures
Capital expenditures and reclamation fund contributions	$	(159,398)	$	(79,165)	101
Property acquisitions		(586)		(72,745)	(99)
Corporate acquisitions		(863,723)		(173,657)	397
Property dispositions		45,100		10,717	321
Net capital expenditures	$	(978,607)	$	(314,850)	211
Funded By
Cash flow net of declared distributions to unitholders and non-controlling interest	$	77,114	$	19,654	292
Increase (decrease) in long-term debt		325,771		(77,087)	(523)
Bridge Financing		-		158,184	(100)
Repayment of bridge financing		-		(158,184)	100
Issue of convertible debentures, net of cost		239,822		48,000	400
Redemption of convertible debentures		(2,997)		-	-
Issue of trust units, net of cost; excluding DRIP		377,362		301,110	25
DRIP proceeds		18,443		19,866	(7)
Change in working capital, including cash, payment of financial derivative instruments, sale of assets		(56,908)		3,307	(1,821)
Net capital expenditure funding	$	978,607	$	314,850	211

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

Net asset value

Provident’s net asset value (“NAV”) as at December 31, 2005, is summarized in the table below. The net asset value is calculated on a diluted basis, which includes exchangeable shares and unit options, and is presented at eight percent and 10 percent discounted cash flow cases. The pricing used at both December 31, 2005 and December 31, 2004 is derived from the McDaniel’s report.

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($ 000s except per unit data)				PV 8%	PV 10%
Net Asset Value:
	Present value of proved plus probable oil and natural
	gas reserves (1)		$	1,690,313	$       1,546,281
	Midstream assets			1,552,415	1,331,409
	Add:
		Working Capital		88,504	88,504
		Land (3) (4)		52,328	52,328
		Proceeds from Options		35,619	35,619
		Cash Reserved for Future Reclamation		1,872	1,872
		Investments		3,758	3,758
	Less:
		Financial Hedging Losses		(14,149)	(14,149)
		Long Term Debt		(884,604)	(884,604)
		Non-controlling interest - USOGP operations		(11,885)	(11,885)
Consolidated Provident Net Asset Value			$	2,514,171	$     2,149,133
Consolidated Provident Net Asset Value per Unit			$	13.04	$             11.15
2004 comparatives
Consolidated Provident Net Asset Value per Unit			$	8.78	$               7.61
(1) Evaluated by McDaniel, NSA and CGA; pricing is McDaniel pricing effective December 31, 2005
(2) The Midstream assets represent discounted estimated cash flow streams (EBITDA less maintenance capital) for 25 years
(3) Canadian land holdings evaluated by Seaton Jordan & Associates Ltd. effective December 31, 2005
(4) U.S. land holdings are included at the market value assigned at the date of acquisitions

Asset Retirement Obligation

Year ended December 31,
($ 000s)		2005		2004	% Change
Carrying amount, beginning of period	$	40,506	$	33,182	22
Corporate acquisitions		9,161		12,171	(25)
Change in estimate		2,884		(2,429)	219
Increase in liabilities incurred during the period		1,784		166	975
Settlement of liabilities during the period		(2,614)		(4,971)	47
Decrease in liabilities due to disposition		(13,612)		-	-
Accretion of liability		3,024		2,387	27
Carrying amount, end of period	$	41,133	$	40,506	2

The asset retirement obligation (ARO) increased by $0.6 million to $41.1 million during 2005.

The Trust’s asset retirement obligation is based on the Trust’s net ownership in wells, facilities and the midstream assets and represents management’s estimate of the costs to abandon and reclaim those wells, facilities and midstream assets as well as an estimate of the future timing of the costs to be incurred. Estimated cash flows have been discounted at the Trust’s credit-adjusted risk free rate of sevenpercent and an inflation rate of twopercent.

The total undiscounted amount of future cash flows required to settle asset retirement obligations related to oil and gas operations is estimated to be $293.0 million. Payments to settle oil and gas asset retirement obligations occur over the operating lives of the assets estimated to be from two to 50 years.

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The total undiscounted amount of future cash flows required to settle the midstream asset retirement obligations is estimated to be $179.3 million. The estimated costs include such activities as dismantling, demolition and disposal of the facilities as well as remediation and restoration of the surface land. Payments to settle the Midstream asset retirement obligations are expected to occur subsequent to the closure of the facilities and related assets. Settlement from the balance sheet date of these obligations is expected to occur over 30 to 45 years.

Non-cash unit based compensation

Non-cash unit based compensation include expenses or recoveries associated with Provident’s unit option plan, restricted and performance unit plan, unit appreciation rights and other unit based compensation plans. Provident accounts for the unit option plan using the fair value of the option, at the time of issue. The other unit based compensation is recorded at the estimated fair value of the notional units granted. Compensation expense associated with the plans is deferred and recognized in earnings over the vesting periods of each plan. Provident recorded a non-cash expense of $9.8 million for the year ended December 31, 2005 (2004 -$1.8 million).

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Canadian OGP segment review (COGP)

Crude oil price

The following prices are net of transportation expense.

COGP	Year ended December 31,
($ per bbl)		2005		2004	% Change
Oil per barrel
WTI (US$)	$	56.56	$	41.43	37
Exchange rate (from US$ to Cdn$)	$	1.21	$	1.30	(7)
WTI expressed in Cdn$	$	68.44	$	53.86	27
COGP realized crude oil and natural gas liquids price before hedging (Cdn$)	$	45.25	$	36.81	23
COGP realized light/medium oil price before hedging (Cdn$)	$	52.02	$	42.79	22
COGP realized heavy oil price before hedging (Cdn$)	$	31.33	$	28.72	9
COGP realized natural gas liquids price before hedging (Cdn$)	$	49.15	$	40.61	21

For the year ended December 31, 2005 COGP’s realized oil and natural gas liquids price, prior to the impact of hedging, increased by 23 percent to average $45.25 compared to $36.81 in 2004. The 2005 increase related to a 37 percent higher US$ WTI crude oil price partially offset by a stronger Canadian dollar, wider pricing differentials on all crude oil streams and a reduction in Provident’s heavy oil volumes as a percentage of its oil production mix.

Natural Gas Price

The following prices are net of transportation expense.

COGP
	Year ended December 31,
($ per mcf)		2005		2004	% Change
AECO monthly index (Cdn$) per mcf	$	8.49	$	6.79	25
Corporate natural gas price per mcf before hedging (Cdn$)	$	8.42	$	6.59	28

For the year ended December 31, 2005 COGP’s realized natural gas price, prior to the impact of hedging, increased 28 percent as compared to 2004, comparable to the increase in the benchmark AECO monthly index price.

Production

	Year ended December 31,
COGP
	2005	2004	% Change
Daily production
Crude oil - Light/Medium (bpd)	8,058	7,995	1
- Heavy (bpd)	4,358	6,608	(34)
Natural gas liquids (bpd)	1,572	1,482	6
Natural gas (mcfd)	74,936	76,174	(2)
Oil equivalent (boed) (1)	26,477	28,781	(8)
(1) Provident reports equivalent production converting natural gas to oil on a 6:1 basis.

For the year ended December 31, 2005, COGP production averaged 26,477 boed, an eight percent decrease compared to 28,781 boed in 2004. The production volumes added through drilling and optimization activities were more than offset by natural production declines including higher than expected declines in heavy oil and the disposition of 2,100 boed of production in September 2005. COGP’s heavy oil production decline was higher due to

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an increase in water production at Provident’s heavy oil field, Kiscoty. Production rates at Kiscoty have now stabilized and Provident’s other heavy oil fields have declines consistent with similar type properties. The lower percentage variance in light/medium oil, natural gas and natural gas liquids reflect a full year of production in the 2005 averages for the Viracocha and Olympia acquisitions as well as both a 39 percent increase in 2005 capital expenditures over 2004 and a shift in capital spending towards natural gas and light/medium oil projects.

Provident does not have any single property providing greater than 10 percent of total production, which mitigates exposure to production failure.

Additions to production through internal capital replaced approximately 48 percent of proved plus probable reserves before revisions. COGP’s 2005 development activities were hampered by poor weather conditions in the second and third quarters of 2005, which delayed overall development activities.

COGP’s production summarized by core areas is as follows:

COGP
Year ended December 31, 2005	West Central Alberta	Southern Alberta	Southern Saskatchewan	Lloydminister	Other	Total
Daily production
Crude oil - Light/Medium (bpd)	1,300	2,722	2,559	1,470	7	8,058
- Heavy (bpd)	-	-	-	4,358	-	4,358
Natural gas liquids (bpd)	1,406	149	1	16	-	1,572
Natural gas (mcfd)	40,198	26,345	6,462	1,909	22	74,936
Oil equivalent (boed) (1)	9,406	7,262	3,636	6,162	11	26,477

COGP
Year ended December 31, 2004	West Central Alberta	Southern Alberta	Southern Saskatchewan	Lloydminister	Other	Total
Daily production
Crude oil - Light/Medium (bpd)	1,355	2,581	2,881	1,164	14	7,995
- Heavy (bpd)	-	-	-	6,608	-	6,608
Natural gas liquids (bpd)	1,342	119	2	14	5	1,482
Natural gas (mcfd)	44,503	24,391	3,180	3,598	502	76,174
Oil equivalent (boed) (1)	10,114	6,765	3,413	8,386	103	28,781
(1) Provident reports equivalent production converting natural gas to oil on a 6:1 basis.

Internal development activities included 132.2 net wells drilled for the year ended December 31, 2005. Provident’s most active area, southern Saskatchewan realized 70.4 net wells drilled. The focus of southern Saskatchewan is a shallow gas drilling program that will realize production and reserve additions for several years. Although poor weather conditions delayed tie-in operations during the second and third quarters of 2005, Provident continued to bring these wells on production in the fourth quarter of 2005. Provident’s other core areas remain active with additional activity in southern Alberta where Provident is actively drilling shallow gas wells and in Lloydminster where Provident is drilling low risk heavy oil wells. In West Central Alberta, Provident continues its strategy of farming out high risk exploration land to generate cash flow with minimal or no capital outlay.

As a result of the non-core properties disposition on September 29, 2005, normal underlying declines rates and Provident’s budgeted 2006 capital expenditure program, Provident expects COGP production for the full year of 2006 to average between 19,000 boed and 21,000 boed.

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Revenue and royalties

COGP
	Year ended December 31,
($ 000s except per boe data)		2005		2004	% Change
Oil
Revenue	$	202,845	$	194,366	4
Realized loss on non-hedging derivative instruments		(42,700)		(54,997)	(22)
Royalties (net of ARTC)		(40,067)		(38,885)	3
Net revenue	$	120,078	$	100,484	19
Net revenue (per barrel)	$	26.50	$	18.80	41
Royalties as a percentage of revenue		19.8%		20.0%
Natural gas
Revenue	$	230,195	$	183,704	25
Realized loss on non-hedging derivative instruments		(5,608)		(10,369)	(46)
Royalties (net of ARTC)		(48,484)		(40,813)	19
Net revenue	$	176,103	$	132,522	33
Net revenue (per mcf)	$	6.44	$	4.75	36
Royalties as a percentage of revenue		21.1%		22.2%
Natural gas liquids
Revenue	$	28,203	$	22,024	28
Royalties		(6,852)		(5,492)	25
Net revenue	$	21,351	$	16,532	29
Net revenue (per barrel)	$	37.21	$	30.48	22
Royalties as a percentage of revenue		24.3%		24.9%
Total
Revenue	$	461,243	$	400,094	15
Realized loss on non-hedging derivative instruments		(48,308)		(65,366)	(26)
Royalties (net of ARTC)		(95,403)		(85,190)	12
Net revenue	$	317,532	$	249,538	27
Net revenue per boe	$	32.86	$	23.69	39
Royalties as a percentage of revenue		20.7%		21.3%
Note: the above figures are presented net of transportation expenses.

For the year ended December 31, 2005 COGP production revenue was $461.2 million, an increase of 15 percent from $400.1 million in 2004. The increase in revenue is a result of a 23 percent increase in Provident’s realized crude oil, natural gas liquids and a 28 percent increase in Provident’s natural gas prices offset by lower production. Royalties as a percentage of revenue have remained relatively constant at approximately 21 percent compared to the prior year. The preceding factors, as well as the opportunity cost of hedging activities, account for net revenue of $317.5 million in 2005, 27 percent above the $249.5 million recorded in 2004.

Net revenue per boe in 2005 increased 39 percent to $32.86 from $23.69 in 2004 resulting primarily from the increases in realized prices described above and a reduction of lower priced heavy oil volumes to 16 percent in 2005 compared to 23 percent in 2004.

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Production expenses

COGP	Year ended December 31,
($ 000s, except per boe data)		2005		2004	% Change
Production expenses	$	95,278	$	90,330	5
Production expenses (per boe)	$	9.86	$	8.58	15

For the year ended December 31, 2005 production expenses increased five percent to $95.3 million from $90.3 million and increased by 15 percent to $9.86 per boe from $8.58 per boe in the prior year. Throughout 2005, operating expenses continued to increase in a number of categories including well servicing, maintenance, fluid hauling, and power and fuel and combined with lower production volumes resulted in higher operating costs on a per boe basis. Cost increases in power and fuel, chemicals and well servicing reflect higher commodity prices and labour costs.

Based on the current high commodity price environment and increased levels of activity, Provident expects Canadian operating costs to average $11.25 boe to $11.75 per boe for 2006. Commodity prices affect both the cost and demand for services. If commodity prices increase, Provident expects the price of services and labour to increase.

Operating netback

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

COGP	Year ended December 31,
($ per boe)		2005		2004	% Change
Netback per boe
Gross production revenue	$	47.73	$	37.99	26
Royalties (net of ARTC)		(9.87)		(8.08)	22
Operating costs		(9.86)		(8.58)	15
Field operating netback		28.00		21.33	31
Realized loss on non-hedging derivative instruments		(5.00)		(6.18)	(19)
Operating netback after non-hedging derivative instruments	$	23.00	$	15.15	52

The 2005 field operating netback of $28.00 per boe was 31 percent above the $21.33 per boe for the prior year. This reflects COGP’s higher realized prices for natural gas and crude oil and natural gas liquids. These prices combined with a shift in COGP’s production mix to include more high netback natural gas and less low netback heavy oil results in a significant improvement in the field operating netback. Royalties, which are price sensitive, increased by 22 percent on a boe basis reflecting higher prices, prior to the impact of hedging. The 2005 operating netbacks after hedging increased by 52 percent to $23.00 from $15.15 in the prior year reflecting the explanation above as well as reduced hedging opportunity costs of $5.00per boe compared to $6.18 in the prior year.

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General and administrative

The following table does not incorporate the COGP portion of non-cash unit based compensation charges associated with Provident’s unit option plan and restricted and performance unit plan. A non-cash expense of $2.6 million was recorded in 2005.

COGP	Year ended December 31,
($ 000s, except per boe data)		2005		2004	% Change
Cash general and administrative	$	18,552	$	16,439	13
Cash general and administrative per boe	$	1.92	$	1.56	23

In 2005 COGP general and administrative expenses increased 13 percent to $18.6 million compared to $16.4 million in 2004. On a boe basis, general and administrative expenses increased 23 percent to $1.92 per boe in 2005 compared to the prior year. The increase in general and administrative expenses reflects additional costs associated with a more competitive landscape affecting the cost of hiring and compensating employees and consultants as well as increases in rent, insurance and compliance and reporting costs.

COGP operations are capable of absorbing additional production, particularly in existing core areas, with little impact on general and administrative expenses. For 2006 general and administrative costs will be a focus as costs associated with compliance (including costs associated with the implementation of procedures and documentation to be in compliance with the U. S. Sarbanes-Oxley Act), and the increasingly competitive landscape will continue to have an impact.

Provident’s accounting policies result in no capitalized general and administrative expense for its COGP business unit.

Capital expenditures

COGP
	Year ended December 31,
($ 000s)		2005		2004
Capital expenditures - by area
West central and southern Alberta	$	32,027	$	24,299
Southeast and southwest Saskatchewan		41,643		25,810
Lloydminster		9,865		10,215
Office and other		1,867		1,130
Total additions	$	85,402	$	61,454
Capital expenditures - by category
Geological and geophysical	$	8,473	$	7,725
Drilling, recompletions, and workovers		41,315		34,012
Facilities and equipment		33,626		18,604
Other capital		1,988		1,113
Total additions	$	85,402	$	61,454
Property acquisitions		586		5,873
Property dispositions	$	45,100	$	13,717

In 2005, Provident’s COGP business unit spent $9.9 million in the Lloydminster area primarily on drilling ($7.0 million) and facility work ($2.6 million). In West central Alberta $10.5 million was spent largely on non-operated drilling ($4.3 million) and facility work ($6.0 million). In southern Alberta $21.5 million was spent on drilling activities and recompletions ($10.4 million), facility upgrades ($10.0 million) and seismic and mineral rights acquisitions ($1.1 million). Provident spent $41.6 million in the southeast and southwest Saskatchewan core areas

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on acquiring mineral rights for future development ($7.4 million), drilling for shallow gas and recompletions ($19.3 million), and facility work ($14.9 million). Office and other items accounted for $1.9 million of capital.

In 2005 asset dispositions of non-core assets totaled $45.1 million, primarily consisting of the September 29, 2005 non-core properties disposition of $44.6 million compared to $13.7 million to the prior year. COGP will continue to seek opportunities to dispose of its non-core properties given the competitive property market.

Provident’s capital expenditures are partly funded through the Premium Distribution, Distribution Reinvestment and Optional Unit Purchase Plan (DRIP). The DRIP program allows investors to reinvest distributions into trust units. Provident directed proceeds from the DRIP program of $18.4 million in 2005 (2004 - $19.9 million), along with the proceeds from asset dispositions, towards the capital expenditure budget.

The 2006 capital budget approved by the Board of Director’s for COGP is $55.0 million.

Depletion, depreciation and accretion (DD&A)

COGP	Year ended December 31,
($ 000s, except per boe data)			2005		2004
DD&A		$	155,929	$	160,271
DD&A per boe		$	16.13	$	15.21

The COGP DD&A rate of $16.13 per boe increased six percent for 2005 compared to $ 15.21 per boe in 2004. The increase is mainly due to incorporating a full year of higher cost reserves in the 2005 DD&A rate related to the second quarter 2004 acquisitions. The proved reserves were acquired at a higher cost than COGP’s historical asset base. The cost of acquiring or drilling proved reserves in western Canada in an environment with higher commodity prices and increased drilling costs will be reflected in the DD&A rate going forward.

In 2005 DD&A also includes accretion expense associated with asset retirement obligation of $2.5 million (2004 - $2.5 million).

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United States OGP segment review (USOGP)

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

On March 2, 2005 Breitburn acquired Nautilus Resources, LLC, a U.S. private company with operations focused in the Big Horn and Wind River basins of Wyoming for cash consideration of $90.2 million.

Crude oil price

USOGP	Year ended December 31,
($ per bbl)		2005		2004	% Change
Oil per barrel
WTI (US$)	$	56.56	$	41.43	37
Exchange rate (from US$ to Cdn$)	$	1.21	$	1.30	(7)
WTI expressed in Cdn$	$	68.44	$	53.86	27
USOGP realized crude oil and natural gas liquids price before hedging (Cdn$)	$	57.76	$	53.24	8
USOGP realized light/medium oil price before hedging (Cdn$)	$	57.80	$	52.42	10
USOGP realized natural gas liquids price before hedging (Cdn$)	$	45.12	$	49.33	(9)

The majority of USOGP oil production is light, sweet crude that attracts smaller differentials to benchmark prices relative to heavier blends. However, oil production from the Nautilus properties is heavier and attracts slightly wider differentials. Production from the former Nautilus properties represents approximately 26 percent of 2005 production.

Production

	Year ended December 31,
USOGP		2005	2004	% Change
Daily production - by product
Crude oil - Light/Medium (bpd)		6,921	3,954	75
Natural gas liquids (bpd)		24	23	4
Natural gas (mcfd)		2,159	1,559	38
Oil equivalent (boed) (1)		7,305	4,237	72
(1) Provident reports equivalent production converting natural gas to oil on a 6:1 basis.

	Year ended December 31,
USOGP		2005	2004	% Change
Daily Production - by area (boed) (1)
Los Angeles		3,949	3,513	12
Santa Maria		1,393	630	121
Wyoming		1,963	94	1,988
		7,305	4,237	72
(1) Provident reports equivalent production converting natural gas to oil on a 6:1 basis.

Production for the year ended December 31, 2005 was 3,068 boed or 72 percent higher than the period June 16 to December 31, 2004. The increase is primarily attributable to a full year of Orcutt production included in 2005 results as well as the contribution of the former Nautilus properties for the period March 2 to December 31, 2005. Production for the former Nautilus properties was 2,260 boed for the period of March 2 to December 31, 2005 while production from Orcutt was 1,393 boed. The exit production rate for 2005 was approximately 7,450 boe per day.

The 2004 daily production figures in this section are for the June to December period.

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

Revenue and royalties

The following table outlines USOGP revenue and royalties by product line. The table excludes revenues earned from operating certain properties ($1.0 million in 2005 and $0.6 million in 2004) on behalf of third parties.

USOGP	Year Ended December 31,
($ 000s, except per boe and mcf amounts)	2005			2004	% Change
Oil
Revenue	$	146,306	$	41,983	248
Realized loss on non-hedging derivative instrument		(16,323)		(425)	3,741
Royalties		(14,022)		(4,009)	250
Net revenue	$	115,961	$	37,549	209
Net revenue (per bbl)	$	45.90	$	47.72	(4)
Royalties as a percentage of revenue		9.6%		9.5%
Natural gas
Revenue	$	7,101	$	2,482	186
Royalties		(988)		-	-
Net revenue	$	6,113	$	2,482	146
Net revenue (per mcf)	$	7.76	$	8.00	(3)
Royalties as a percentage of revenue		13.9%		0.0%
Natural gas liquids
Revenue	$	395	$	223	77
Royalties		(9)		-	-
Net revenue	$	386	$	223	73
Net revenue (per bbl)	$	44.05	$	49.28	(11)
Royalties as a percentage of revenue		2.4%		0.0%
Total
Revenue	$	153,802	$	44,688	244
Realized loss on non-hedging derivative instrument		(16,323)		(425)	3,741
Royalties		(15,019)		(4,009)	275
Net revenue	$	122,460	$	40,254	204
Net revenue (per boe)	$	45.93	$	47.74	(4)
Royalties as a percentage of revenue		9.8%		9.0%

Royalty rates in the U.S. are significantly lower than in Canada.

Revenue for the year ended December 31, 2005 is $153.8 million or 244 percent higher than the period from June 16 to December 31, 2004. The increase is attributable to a full year of operations in 2005, increases in commodity prices as well as a full year of production from the Orcutt field acquired in October of 2004 and the Wyoming properties acquired in March of 2005. Net revenue is $122.5 million or 204 percent higher than the $40.3 million of net revenue in the period from June 16 to December 31, 2004. Increases in net revenue from a full year of operations, high commodity prices, production from the Orcutt field and the acquired Wyoming fields were offset by realized losses on non-hedging derivative instruments. Royalties as a percentage of revenue are up slightly as royalties on the acquired Wyoming properties are slightly higher than those incurred in Southern California operations.

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Production expenses

	Year ended December 31,
USOGP
($ 000s, except per boe amounts)		2005		2004	% Change
Production expenses	$	39,513	$	13,173	200
Production expenses (per boe)	$	14.82	$	15.62	(5)

Production expenses increased $26.3 million or 200 percent to $39.5 million in the year ended December 31, 2005 compared to the period June 16 to December 31, 2004. The increase is attributable to a full year of operations from the Orcutt field acquisition in October of 2004 and the acquired Wyoming properties in March of 2005. Production expenses per boe for the year ended December 31, 2005 are $0.80 or five percent lower than the period June 16 to December 31, 2004. The decrease is primarily attributable to the addition of the former Nautilus properties in Wyoming. These properties have lower production expenses than the production from Southern California.

General and administrative

The following table does not incorporate the USOGP portion of non-cash unit based compensation expense associated with the USOGP unit appreciation rights plan and an internal management charge. A year to date non-cash expense for the unit appreciation rights plan and the internal management charge of $6.1 million and $1.7 million respectively has been recorded in 2005.

	Year ended December 31,
USOGP
($ 000s, except per boe amounts)		2005		2004	% Change
Cash general and administrative	$	11,490	$	4,113	179
Cash general and administrative per boe	$	4.31	$	4.88	(12)

Cash general and administrative expenses increased $7.4 million or 179 percent in the year ended December 31, 2005 compared to the period June 16 to December 31, 2005. This increase is primarily attributable to a full year of operations. Cash general and administrative expenses for the year ended December 31, 2005 declined $0.57 per boe or 12 percent compared to the period June 16 to December 31, 2004. This is primarily attributed to the additions of Orcutt and the former Nautilus properties which were acquired without a significant increase in cash general and administrative expenses.

Operating netback

	Year ended December 31,
USOGP
($ per boe)		2005	2004		% Change
USOGP oil equivalent netback per boe
Gross production revenue	$	57.68	$	53.00	9
Royalties		(5.63)		(4.76)	18
Operating costs		(14.82)		(15.62)	(5)
Field Operating Netback	$	37.23	$	32.62	14
Non-hedging derivative instruments		(6.12)		(0.50)	1,124
Operating netback after non-hedging derivative instruments	$	31.11	$	32.12	(3)

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	Year ended December 31,
USOGP
($ per bbl)		2005	2004		% Change
USOGP crude oil and NGL's netback per bbl
Gross production revenue	$	57.87	$	53.33	9
Royalties		(5.54)		(5.07)	9
Operating costs		(14.82)		(15.62)	(5)
Field Operating Netback	$	37.51	$	32.64	15
Non-hedging derivative instruments		(6.44)		(0.54)	1,093
Operating netback after non-hedging derivative instruments	$	31.07	$	32.10	(3)

	Year ended December 31,
USOGP
($ per mcf)		2005	2004		% Change
USOGP natural gas netback per mcf
Gross production revenue	$	9.01	$	8.00	13
Royalties		(1.25)		-	-
Operating costs		(2.47)		(2.60)	(5)
Field and Operating Netback	$	5.29	$	5.40	(2)

USOGP operating netbacks remained strong throughout 2005 due to high commodity prices.

Income taxes and cash taxes

USOGP	Year ended December 31,
($ 000s)		2005		2004	% Change
Current and withholding taxes	$	5,628	$	1,201	369
Future income tax expense		18,320		-	-
	$	23,948	$	1,201	1,894

Current and withholding taxes include current U.S. federal and state income taxes as well as accrued or paid U.S. withholding taxes on distributions that have been or will be made from BreitBurn Energy LP to Provident. The 2005 future income tax expense of $18.3 million (2004 - nil) resulted from deduction of drilling costs for tax purposes in 2005 which are capitalized for accounting purposes and from changes to estimated tax pools.

Depletion, depreciation and accretion (DD&A)

	Year ended December 31,
USOGP
($ 000s, except per boe amounts)		2005		2004	% Change
DD&A	$	25,553	$	7,402	245
DD&A per boe	$	9.58	$	8.78	9

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

Depletion, depreciation and accretion expenses are significantly greater in 2005 than in 2004 due to the additions of the former Nautilus properties as well as Orcutt. Additionally, the 2004 period presented is from June 15 to December 31, 2004.

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On a per boe basis the DD&A rate is up $0.80 or nine percent from 2004. This is primarily associated with the Nautilus properties, the reserves which were more expensive per boe due to the shorter reserve lives than the California properties and thus, slightly higher depletion, depreciation and accretion rates.

Capital expenditures

USOGP
	Year ended December 31,
($ 000s)		2005		2004
Capital expenditures - by category
Geological and geophysical	$	4,608	$	761
Drilling, recompletions, and workovers		29,470		10,421
Facilities and equipment		18,035		1,228
Other capital		784		-
Total additions	$	52,897	$	12,410
Property acquisitions		-		66,872
Property dispositions	$	-	$	-

USOGP capital expenditures for the year ended December 31, 2005 totaled $52.9 million. Of this total $38.7 million related to drilling, optimization and facility upgrades at West Pico, Santa Fe Springs and Orcutt. $5.0 million was directed at optimization projects in Wyoming, $3.7 million was directed to the purchase of real estate adjacent to the West Pico facility, and $5.5 million was directed at optimization projects at smaller fields as well as office equipment.

USOGP capital expenditures for the year ended December 31, 2004 totaled $79.3 million, including property acquisitions. This includes $58.5 million for the Orcutt property acquisition, $3.1 million to increase BreitBurn’s working interest in certain wells at West Pico and Sawtelle, $7.3 million on drilling, optimization and facility upgrades at West Pico, $5.0 million on drilling, optimization and facility upgrades at Santa Fe Springs and $5.5 million on facility upgrades and optimization programs at other USOGP properties. Optimization capital was partially focused at returning previously uneconomic wells to production due to the high commodity price environment.

The capital expenditure budget for USOGP in 2006 is $51.0 million.

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Midstream services and marketing business segment

NGL Acquisition

On December 13, 2005 Provident acquired NGL assets and the Kinetic marketing entity for $772.3 million, net of cash acquired, including $38.9 million of working capital that includes $85.5 million of inventory. The 2005 results incorporate the results of operations associated with these midstream assets since acquisition.

The assets

The Midstream business unit extracts, processes, stores, transports and markets natural gas liquids (NGL). This is accomplished within two integrated systems and complementary assets. The Redwater system is comprised of three core assets:

o   100 percent ownership of the Redwater NGL Fractionation Facility, a 65,000 barrels per day (bbl/d) fractionation, storage and transportation facility that includes 12 pipeline receipt and delivery points, railcar loading facilities with direct access to CN and CP rail, two propane truck loading facilities, and six million gross barrels of salt cavern storage. The facility can process high-sulphur NGL streams and is one of only two facilities in western Canada capable of extracting ethane from the natural gas liquids stream.

o   43.3 percent ownership of the 38,500 bbl/d Younger NGL extraction plant located at Taylor in northeastern British Columbia that supplies 16,700 bbl/d of net NGLs for processing at Redwater.

o   100 percent ownership of the 565 kilometer proprietary Liquids Gathering System (“LGS”) that runs along the Alberta-British Columbia border providing access to a highly active basin for liquids-rich natural gas exploration and exploitation. Provident also has long-term shipping rights on the Pembina Peace Pipeline that extends the product delivery transportation network through to the Redwater fractionation facility.

The recently acquired Empress/Sarnia system is comprised of 5 core assets:

o   Approximately 2.0 Bcf/d of extraction capacity at Empress Alberta. This is the combination of 60 percent ownership of the 1.2 Bcf/d capacity Provident Empress NGL Extraction plant, 12.4 percent ownership in the 1.1 Bcf/d capacity ATCO Plant, 8.3 percent ownership in the 2.4 Bcf/d capacity Duke Plant and 33.0 percent ownership in the 2.7 Bcf/d capacity BP Empress 1 Plant.

o   100 percent ownership of a 50,000 bbl/d debutanizer at Empress Alberta.

o   50 percent ownership in the 130,000 bbl/d Kerrobert Pipeline and 2.5 mmbbl underground storage facility near Kerrobert, Saskatchewan which facilitates injection into the Enbridge Pipeline System. Along the Enbridge Pipeline System, Provident holds 18.3 percent ownership of 300,000 bbls of Superior Storage staging facility and 18.3 percent ownership of the 6,600 bbl/d Superior Depropanizer.

o   In Sarnia, Ontario, 10.3 percent ownership of an approximately 150,000 bbl/d fractionator, 1.7 mmbbl of raw product storage capacity and 18 percent of 5.0 mmbbl of finished product storage and rail, truck and pipeline terminalling.

o   49 percent interest in a partnership which owns the 6.9 mmbbl Marysville Underground Storage Terminal (MUST).

Complementary to the above assets is the following acquisition:

o   100 percent ownership of the NGL marketing group Kinetic, operating a fleet of approximately 700 rail cars and a propane distribution terminal at Lynchburg, Virginia.

The majority of the property, plant and equipment are depreciated over 40 years on a straight-line basis reflecting the long useful life of these assets.

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Midstream and marketing services

Provident’s midstream services offer customers several types of services and contractual arrangements, which include:

Fee for service processing - (“Transportation and Fractionation - T&F”) In these arrangements, NGL owners (typically natural gas producers) deliver to Provident their NGLs and pay fees for the transportation, fractionation, short term storage and distribution of their NGL barrels. The NGL owner is responsible for marketing their product.

Marketing Services: This service involves NGL owners delivering their product to Provident with Provident taking title and paying the NGL owner an amount that is a delivery price of raw NGLs that is discounted to postings. The discounted purchase price that Provident pays for the product covers the costs of transportation, fractionation, storage, and marketing of the NGLs.

Storage: NGL owners pay fees to store their NGLs.

Transport and Distribution: NGL owners or purchasers pay fees to transport NGLs through the LGS pipeline and use rail and truck loading facilities at Redwater, Sarnia, Marysville and Lynchburg.

The contracts

At the Redwater facility, approximately 75 percent of the available capacity is contracted through fee-for-service or fixed margin arrangements with major oil and natural gas producers and petrochemical businesses. As a result of these contracts, approximately 68 percent of Redwater’s system capacity is contracted for 10 years or longer.

As with most Alberta straddle plants, all ethane produced from Provident’s collective Empress interests is sold under long term contracts.

Plant capacities and throughput

The Redwater facility (100 percent ownership) was constructed between 1996 and 1998. It is the most modern facility of its type in Canada and is currently designed for throughput capacity of 65,000 bpd of NGLs with an expectation to average approximately 63,000 bpd.

The Provident Empress plant (60 percent ownership) was commissioned in September 1996 and subsequently expanded in 1999 and 2003. It is one of the newest and most cost efficient facilities at Empress. The plant has a design capacity of 1.2 Bcf/d to extract ethane and propane-plus.

The BP Empress 1 plant (33 percent ownership) base plant was commissioned in 1971 with expansions commissioned in 1994 and 2005. The base plant has a capacity of 1.7 Bcf/d to extract ethane and propane-plus. The 1994 train addition has 1 Bcf/d capacity to extract propane-plus.

The Duke plant (8.3 percent ownership) was commissioned in 1964. It has a capacity of 2.4 Bcf/d. It has the following unique aspects (1) an airstrip; (2) treatment for ethane to remove CO₂; (3) a Ferus CO₂ plant hosted on a shared operating cost basis; (4) the only plant at the Empress Complex with full ethane-plus fractionation facilities; and (5) the ability to dispatch products by truck, rail, the IPF Jenner Pipeline, the Kerrobert Pipeline, and the PTC Pipeline.

The ATCO Plant (12.4 percent ownership) was commissioned in 1982, and expanded in 1999, and has an extraction capacity of 1.1 Bcf/d.

The Provident Debutanizer (100 percent ownership) was commissioned at the end of 2005. It has a design capacity of 50,000 bbl/d of propane-plus and will remove condensate currently delivered to the Kerrobert Pipeline.

The Kerrobert Pipeline (50 percent ownership) is an NEB regulated pipeline constructed in 1971 to deliver propane-plus product from the Empress Comples to Kerrobert Storage near Kerrobert, Saskatchewan. It has a capacity of 130,000 bbl/d. Kerrobert Storage was also developed in 1971 and has a design capacity of 2.5 mmbbls.

Superior Storage (18.3 percent ownership) has a design capacity of 300,000 bbls and was built to accommodate the change in shipping rates within the Enbridge Pipeline system.

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The Superior Depropanizer was built in 1991 and is designed to process approximately 10,000 bbl/d of propane-plus and extract 6,600 bbl/d of propane.

Sarnia Fractionation (10.3 percent ownership) began operations in 1970. It has an average capacity of approximately 150,000 bbl/d.

Provident has a 49 percent partnership interest in the Marysville Partnership which owns the Marysville Underground Storage Terminal (“MUST”). This storage terminal has a capacity of approximately 6.9 MMbbls for raw and specification NGL product.

Operations - managed NGL volumes

In 2005, Provident Midstream managed approximately 64,740bpd compared to57,484 bpd in 2004 and closed the year with managed volumes of approximately 140,640 bpd. This includes activity from the newly acquired NGL assets since acquisition on December 13, 2005. In addition, throughput at Redwater has improved with the completion of an operating enhancement.

Revenues

2005 product sales and services revenues of $908.1 million after elimination of intersegment transactions, include product sales related to T&F processing and marketing, revenues generated through storage and distribution services and oil sales generated through oil marketing activities (2004 - $840.2 million). The increase in revenue is the result of the Midstream NGL Acquisition ($67.2 million of revenue in 2005) as well as higher product prices offset by the sale of certain crude oil marketing contracts on May 1, 2005. The majority of NGL revenues are earned pursuant to the long-term contracts and annual evergreen purchase and sales commitments.

Cost of goods sold

The cost of goods sold of $786.6 million for 2005 relates to NGL product sales revenue included in the product sales and services revenue, where Provident has purchased natural gas liquids and to oil purchased pursuant to oil marketing activities (2004 - $741.6 million). The increase in cost of goods sold is the result of the Midstream NGL Acquisition ($58.1 million cost of goods sold in 2005) as well as higher product prices offset by the sale of certain crude oil marketing contracts of May 1, 2005. The NGL costs would be applicable to the fixed margin contracts and a small percentage of volume delivered from the Younger facility on which Provident manages extraction economics. For 2005, the majority of the natural gas liquids were purchased pursuant to long-term contracts and annual evergreen purchase commitments which is consistent with previous years.

Product Margin

Product margin is the revenue less the cost of good sold and is representative of the margins obtained on marketed products, however it is affected by fee for service revenues that are grouped in with product sales and service revenues. In 2005, $121.5 million or a 13 percent product margin was generated on $908.1 million of product sales and service revenues compared to $98.5 million or a 12 percent product margin generated on $840.2 million of 2004 product sales and service revenues. The 2005 product margin would be expected to be higher than the 2004 which included the lower margin crude oil marketing activities. In future periods the product margin will be subject to a wider range of variability driven by the Midstream NGL Acquisition that increases exposure to extraction economics.

Fractionation Spread Support Program

As part of the Midstream NGL Acquisition, the vendor has agreed to provide a near-term fractionation spread support program. The program provides Provident with up to $75 million of support over the next two years if fractionation spreads are below historic levels. This program intended to ensure that Provident achieves the long-term average fractionation spreads which the NGL business has attained historically through to November 2007. This program is intended to provide consistent and stable cash flow and distributions for Unitholders. In certain circumstances, the vendor will have the ability to recover the amounts provided under the support program until October 31, 2008, if fractionation spreads exceed historic levels. Provident’s long term risk management strategy is focused on locking in fractionation spread margins, with the objective of stabilizing cash flow over the longer term.

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The impact of the agreement on 2005 was a receipt of $5.2 million that resulted in a reduction in the cost of goods available for sale with no comparative for 2004.

Other expenses

The Redwater plant is still the newest and most cost effective compared to other North American facilities of this type. In 2005, operating costs of $36.4 million (2004 - $38.0 million) reflect cost reductions at the Younger NGL extraction plant. General and administrative expenses of $11.6 million for 2005 (2004 - $6.6 million), interest of $4.9 million for 2005 (2004 - $7.2 million), and depreciation of $11.8million for 2005 (2004 - $9.6 million). Increases in general and administrative expenses reflect additional costs associated with a more competitive landscape affecting the cost of hiring and compensating employees and consultants as well as increases in rent, insurance and compliance and reporting costs. Increases in general and administrative expenses in 2005 resulted from allocation of costs in the fourth quarter resulting from the Midstream NGL Acquisition which was negotiated, announced and closed in fourth quarter 2005 and increased direct costs.

Earnings before interest, taxes, depletion, depreciation, accretion, and other non-cash items (“EBITDA”)and cash flow from operations

For 2005, Provident’s Midstream business unit generated EBITDA of $70.7 million and cash flow from operations of $66.3 million. Actual EBITDA performance exceeded management’s 2005 EBITDA forecast of $40.0 million. These results compare to 2004 EBITDA of $50.1 million and cash flow of $42.6 million. The increase over 2004 is primarily due to stronger product premiums in 2005 as well as an increase in product prices over the period.

Management uses EBITDA to analyze the operating performance of the midstream business unit. EBITDA as presented does not have any standardized meaning prescribed by Canadian GAAP and therefore it may not be comparable with the calculation of similar measures for other entities. EBITDA as presented is not intended to represent operating cash flow or operating profits for the period nor should it be viewed as an alternative to cash flow from operating activities, net earnings or other measures of financial performance calculated in accordance with Canadian GAAP. All references to EBITDA throughout this report are based on Earnings before interest, taxes, depletion, depreciation, accretion, and other non-cash items (“EBITDA”).

Gain on sale of marketing contracts

On May 1, 2005 the Trust disposed of certain crude oil marketing contracts for net proceeds of $5.5 million and recorded a gain of $5.2 million net of disposal costs. The sale of these contracts will not materially impact cash flows and has been recognized through the Midstream services and marketing segment. During 2004 the crude oil marketing business generated $203.0 million in revenues. For the four months period ended April 30, 2005 the crude oil marketing business generated $105.7 million in revenues. The sale of these contracts is not expected to have a material impact on the cash flow or net income of the Midstream segment.

Capital expenditures

Midstream capital expenditures, excluding corporate acquisitions, for 2005 totaled $18.2 million. $17.0 million of the capital was spent on new product handling facilities including the new condensate offloading and terminalling facilities recently announced as well as truck loading facilities and a rail yard expansion. The remainder of the capital was spent on pipeline integrity and on the Younger plant as well as on enhancing the overall efficient and safe operations of the fractionation plant. This compared to $3.0 million spent in 2004 on pipeline integrity, efficiency and safety projects and $0.7 million spent on product handling expansion.

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Foreign ownership

Based on information received from our transfer agent and financial intermediaries in March 2006, an estimated 85 percent of our outstanding trust units are held by non-residents. However, this estimate may not be accurate as it is based on certain assumptions and data from the security industry that does not have a well-defined methodology to determine the residency of beneficial holders of securities.

The Trust qualifies as a Mutual Fund Trust under the Canadian Income Tax Act because substantially all the value of its asset portfolio is derived from non-taxable Canadian properties, comprised principally of royalties and inter-company debt. Provident monitors on an ongoing basis the value of its asset portfolio to confirm that substantially all of the value of its asset portfolio is derived from non-taxable Canadian properties.

On September 17, 2003 Canadian unitholders approved an amendment to the Trust’s Trust Indenture providing that residency restriction provisions need not be enforced while the Trust continues to qualify as a Mutual Fund Trust under Canadian tax legislation. To allow Provident to remain a Mutual Fund Trust and to execute a business plan that maximizes unitholder returns without regard to the types of assets the Trust may hold, the approved amendment provides for Provident’s board of directors to have sole discretion to determine whether and when it is appropriate to reduce or limit the number of trust units held by non-residents of Canada.

Related party

Property sale

On December 30, 2004, at the conclusion of a competitive process, Provident sold properties to a private company on whose board two of the directors of Provident sit and in which they own shares. The properties were sold for consideration of $3.5 million of which $0.5 million was cash and $3.0 million consisted of 10,000,000 common shares valued at $0.30 per share. The carrying value of these shares are included in investments on the balance sheet. The transaction was recorded at fair value.

Business prospects

Provident intends to execute a balanced portfolio strategy. In the COGP business internal development projects with a board approved capital budget of $55.0million are planned. Acquisitions of interest in properties close to properties already owned or partially owned by Provident will be pursued. In the USOGP business internal development projects are planned with a board approved capital budget of $51.0million. Major corporate or property acquisitions are and will be evaluated. In the Midstream Services business Provident will expand and build upon the business and evaluate additional infrastructure assets with a goal of adding quality assets at reasonable prices. The goal of these strategies is to maintain and increase per unit distributable cash flow and net asset value.

Critical accounting policies

Provident’s accounting policies are described in note 2 to the consolidated financial statements. Certain accounting policies are identified as critical accounting policies because they form an integral part of Provident’s financial position. They also require management to make judgments and estimates based on conditions and assumptions that are inherently uncertain. These accounting policies could result in materially different results should the underlying assumptions or conditions change.

Management assumptions are based on Provident’s historical experience, management’s experience, and other factors that, in management’s opinion, are relevant and appropriate. Management assumptions may change over time, as further experience is gained or as operating conditions change.

Details of Provident’s critical accounting policies are as follows:

Property, plant and equipment

Provident follows the full cost method of accounting, whereby all costs associated with the acquisition and development of oil and natural gas reserves are capitalized. Utilization of the full cost method of accounting

46

requires the use of management estimates and assumptions for amounts recorded for depletion and depreciation of property, plant and equipment as well as for the ceiling test.

The provision for depletion and depreciation is calculated using the unit of production method based on current production divided by Provident’s share of estimated total proved oil and natural gas reserve volumes before royalties. The recoverability of a cost centre is tested by comparing the carrying value of the cost centre to the sum of the undiscounted cash flows expected from the cost centre. If the carrying value is not recoverable the cost centre is written down to its fair value.

Proved reserves are an estimate, under existing reserve evaluation polices, of volumes that can reasonably be expected to be economically recoverable under existing technology and economic conditions. Changes in underlying assumptions or economic conditions could have a material impact on Provident’s financial results. To mitigate these risks management utilizes McDaniel & Associates Consultants Ltd., an independent engineering firm, to evaluate Provident’s Canadian reserves. For Provident’s U.S. based assets management utilizes Cawley, Gillespie & Associates, Inc. and Netherland, Sewell & Associates, Inc., independent engineering firms, to evaluate reserves.

Estimates of future production, oil and natural gas prices and future costs used in the ceiling test are, by their very nature, subject to uncertainty and changes in underlying assumptions could have a material impact on Provident’s financial results.

Asset retirement obligation

Under the asset retirement obligation (ARO) standard, the fair value of asset retirement obligations is recorded as a liability on a discounted basis, when incurred. The value of the related assets are increased by the same amount as the liability and depreciated over the useful life of the asset. Over time the liability is adjusted for the change in present value of the liability or as a result of changes to either the timing or amount of the original estimate of undiscounted future cash flows.

Asset retirement obligation requires that management make estimates and assumptions regarding future liabilities and cash flows involving environmental reclamation and remediation. Such assumptions are inherently uncertain and subject to change over time due to factors such as historical experience, changes in environmental legislation or improved technologies. Changes in underlying assumptions, based on the above noted factors, could have a material impact on Provident’s financial results.

Change in accounting policies

The following change in accounting policy was adopted by Provident in 2005.

Exchangeable securities - non-controlling interest

The Canadian Institute of Chartered Accountants issued an amendment to EIC abstract 151 "Exchangeable Securities Issued by Subsidiaries of Income Trusts" that states that exchangeable securities issued by a subsidiary of an income trust should be reflected as either non-controlling interest or debt on the consolidated balance sheet unless they meet certain criteria. The exchangeable shares issued by Provident Acquisitions Inc. and Provident Energy Ltd. corporate subsidiaries of the Trust are considered under this standard to be transferable to third parties. EIC-151 states that if the exchangeable shares are transferable to a third party, they should be reflected as non-controlling interest. Previously, the exchangeable shares were reflected as a component of unitholders' equity.

As a result of this change in accounting policy, the Trust has reflected non-controlling interest of $8.3 million and $35.9 million, respectively, on the Trust's consolidated balance sheet as at December 31, 2005 and December 31, 2004. Consolidated net income or loss has been adjusted for the earnings attributable to the non-controlling interest of $0.8 million for the year ended December 31, 2005 and $0.5 million for the year ended December 31, 2004. As at June 30, 2005 unitholders' equity was reduced by $11.2 million and non-controlling interest on the consolidated balance sheet increased by $13.0 million. In accordance with the transitional provisions of EIC-151, retroactive application has been applied with restatement of prior periods. The retroactive application of this abstract as at December 31, 2004 was an accumulated loss of $1.5 million. The retroactive accumulated loss adjustments represent the cumulative net income attributable to the non controlling interest for prior periods. Cash flow was not affected by this change.

47

Recent accounting pronouncements

The following new accounting guidelines or standards are applicable to Provident but have not been implemented.

Financial Instruments, Hedges and Comprehensive Income

In 2005, the CICA issued Section 3855 “Financial instruments-recognition and measurement,” Section 3865 “Hedges,” and Section 1530 “Comprehensive Income.” Under these Sections, standards for recognizing and measuring financial assets, financial liabilities and non-financial derivatives have been established. The standards will require the majority of derivatives to be classified as held for trading and will be measured at fair value with gains and losses recognized in net income in the periods in which they arise unless they are part of a hedging relationship. For hedges, the existing requirements for hedge accounting under Accounting Guideline 13 “Hedging relationships” are maintained, with the majority of hedging relationships being stated at fair value with a gain or loss from remeasuring the foreign currency component of its carrying amount being recognized in net income in the period of change together with the offsetting loss or gain on the hedged item attributable to the hedged risk. These new standards also require an entity to present comprehensive income and its components, as well as net income, in its financial statements. This will include certain gains or losses, including foreign currency translation and other amounts arising from changes in fair value. These Sections apply to interim and annual financial statements relating to fiscal years beginning on or after October 1, 2006. The Trust has not evaluated the effect that this standard might have on the consolidated financial statements.

Equity

In 2005, the CICA issued Section 3251 “Equity”. This Section replaces Section 3250 “Surplus” and establishes standards for the presentation of equity and changes in equity during the reporting period. The Section requires an entity to present separately each of the changes in equity during the period, including comprehensive income, as well as components of equity at the end of the period. This Section applies to interim and annual financial statements relating to fiscal years beginning on or after October 1, 2006. The Trust has not evaluated the effect that this standard might have on the consolidated financial statements.

Non-Monetary Transactions

In 2005, the CICA issued Section 3831 “Non-Monetary Transactions”. In this new standard, a commercial substance test replaces the culmination of earnings test as criteria for fair value measurement. This new requirement is effective for non-monetary transactions initiated in periods beginning on or after January 1, 2006. The Trust does not expect the adoption of this abstract to have a material impact on its financial statements.

Conditional Asset Retirement Obligations

In 2005, the CICA issued EIC 159 “Conditional Asset Retirement Obligations”. This abstract clarifies that the term conditional asset retirement obligation as used in CICA 3110 refers to a legal obligation to perform an asset retirement activity in which the timing and/or method of settlement are conditional on a future event that may or may not be within the control of the entity. The obligation to perform the asset retirement activity is unconditional even though uncertainty exists about the timing and/or method of settlement. Thus, the timing and/or method of settlement may be conditional on a future event. Accordingly, an entity is required to recognize a liability for the fair value of a conditional asset retirement obligation if the fair value of the liability can be reasonably estimated. This abstract is to be applied retroactively, with restatement of prior periods, to all financial statements for interim and annual reporting periods ending after March 31, 2006. The Trust does not expect the adoption of this abstract to have a material impact on its financial statements.

48

Business risks

The oil and natural gas trust industry is subject to numerous risks that can affect the amount of cash flow available for distribution to unitholders and the ability to grow. These risks include but are not limited to:

o   fluctuations in commodity price, exchange rates and interest rates;

o   government and regulatory risk in respect of royalty and income tax regimes;

o   operational risks that may affect the quality and recoverability of reserves;

o   geological risk associated with accessing and recovering new quantities of reserves;

o   transportation risk in respect of the ability to transport oil and natural gas to market;

o   capital markets risk and the ability to finance future growth;

o   marketability of oil and natural gas;

o   income tax legislation relating to income trusts; and

o   environmental, health and safety risks.

The midstream industry is also subject to risks that can affect the amount of cash flow available for distribution to unitholders and the ability to grow. These risks include but are not limited to:

o   operational matters and hazards including the breakdown or failure of equipment, information systems or processes, the performance of equipment at levels below those originally intended, operator error, labour disputes, disputes with owners of interconnected facilities and carriers and catastrophic events such as natural disasters, fires, explosions, fractures, acts of eco-terrorists and saboteurs, and other similar events, many of which are beyond the control of the Trust or Provident;

o   the Midstream NGL assets are subject to competition from other gas processing plants, and the pipelines and storage, terminal and processing facilities are also subject to competition from other pipelines and storage, terminal and processing facilities in the areas they serve, and the gas products marketing business is subject to competition from other marketing firms;

o   exposure to commodity price fluctuations;

o   regulatory intervention in determining processing fees and tariffs; and

o   reliance on significant customers.

Provident strives to minimize these business risks by:

o   employing and empowering management and technical staff with extensive industry experience;

o   adhering to a strategy of acquiring, developing and optimizing quality, low-risk reserves in areas where we have technical and operational expertise;

o   developing a diversified, balanced asset portfolio that generally offers developed operational infrastructure, year-round access and close proximity to markets;

o   adhering to a consistent and disciplined Commodity Price Risk Management Program to mitigate the impact that volatile commodity prices have on cash flow available for distribution.

o   marketing crude oil and natural gas to a diverse group of customers, including aggregators, industrial users, well-capitalized third-party marketers and spot market buyers;

o   marketing natural gas liquids and related services to selected, credit worthy customers at competitive rates;

o   maintaining a low cost structure to maximize cash flow and profitability;

o   maintaining prudent financial leverage and developing strong relationships with the investment community and capital providers;

o   adhering to strict guidelines and reporting requirements with respect to environmental, health and safety practices; and

o   maintaining an adequate level of property, casualty, comprehensive and directors’ and officers’ insurance coverage.

49

Unit trading activity

Provident has moved to the New York Stock Exchange as of December 16, 2005. The following table summarizes the unit trading activity of the Provident units for the four quarters ended December 31, 2005 on both the Toronto Stock Exchange and the American Stock Exchange:

		Q1		Q2		Q3		Q4
TSE - PVE.UN (Cdn$)
High	$	12.60	$	13.05	$	14.29	$	14.42
Low	$	11.17	$	11.82	$	12.91	$	12.29
Close	$	11.98	$	12.82	$	14.14	$	12.55
Volume (000s)		26,122		15,951		22,375		30,786
AMEX/NYSE - PVX (US$)
High	$	10.40	$	10.55	$	12.19	$	12.38
Low	$	9.15	$	9.48	$	10.65	$	10.37
Close	$	9.89	$	10.49	$	12.19	$	10.81
Volume (000s)		64,223		46,548		55,372		55,981

Additional information

Additional information concerning Provident can be accessed under Provident’s public filings at www.sedar.com and on Provident’s website at www.providentenergy.com.

Selected annual financial measures

($ 000s except per unit data)		2005		2004		2003
				Restated (1)		Restated (1)
Revenue (net of royalties and financial derivative instruments)	$	1,360,274	$	1,109,857	$	406,329
Net income		96,926		21,225		22,497
Net income per unit-basic		0.61		0.19		0.35
Net income per unit-diluted		0.61		0.19		0.35
Total assets		2,792,270		1,813,582		1,142,955
Long-term financial liabilities (2)		925,737		472,712		389,755
Declared Distributions per unit	$	1.44	$	1.44	$	2.06
(1) see note 3 to consolidated financial statements
(2) includes long term debt and asset retirement obligation

50

Quarterly table

($ 000s except for per unit amounts)	2005
			First			Second		Third		Fourth		YTD
			Quarter(1)			Quarter		Quarter		Quarter		Total
Financial - consolidated
Revenue		$	322,023		$	300,504	$	295,060	$	442,687	$	1,360,274
Cash flow		$	64,137		$	64,435	$	86,318	$	96,298	$	311,188
Net income (loss)		$	(2,783	)	$	26,822	$	18,386	$	54,501	$	96,926
Net income (loss) per unit - basic and diluted		$	(0.02	)	$	0.17	$	0.11	$	0.32	$	0.61
Unitholder distributions		$	51,734		$	57,001	$	59,333	$	62,646	$	230,714
Distributions per unit		$	0.36		$	0.36	$	0.36	$	0.36	$	1.44
Oil and gas production
Cash revenue		$	100,447		$	104,478	$	124,073	$	117,710	$	446,708
Earnings before interest, DD&A, taxes and other non-cash items		$	59,262		$	63,584	$	81,670	$	73,976	$	278,492
Cash flow		$	48,937		$	53,868	$	74,139	$	68,006	$	244,950
Net income (loss)		$	(15,046	)	$	14,681	$	10,702	$	30,437	$	40,774
Midstream services and marketing
Cash revenue		$	245,338		$	186,635	$	180,875	$	293,034	$	905,882
Earnings before interest, DD&A, taxes		$	16,380		$	11,765	$	12,978	$	29,566	$	70,689
and other non-cash items
Cash flow		$	15,200		$	10,567	$	12,179	$	28,292	$	66,238
Net income		$	12,263		$	12,141	$	7,684	$	24,064	$	56,152
Operating
Oil and gas production
Light/medium oil (bpd)			14,388			15,891		15,583		14,051		14,979
Heavy oil (bpd)			5,547			4,644		4,075		3,195		4,358
Natural gas liquids (bpd)			1,756			1,454		1,523		1,653		1,596
Natural gas (mcfd)			80,466			79,126		75,523		73,363		77,095
Oil equivalent (boed)			35,102			35,177		33,768		31,126		33,782
(Cdn $)
Average selling price net of transportation expense
Light/medium oil per bbl		$	49.32		$	51.20	$	62.95	$	55.31	$	54.69
(before hedges)
Light/medium oil per bbl		$	40.93		$	42.18	$	49.82	$	42.52	$	43.90
(including hedges)
Heavy oil per bbl		$	25.85		$	26.03	$	46.74	$	28.62	$	31.33
(before hedges)
Heavy oil per bbl		$	25.78		$	26.03	$	46.74	$	28.62	$	31.31
(including hedges)
Natural gas liquids per barrel		$	45.30		$	47.75	$	54.27	$	49.44	$	49.09
Natural gas per mcf		$	6.76		$	7.29	$	8.43	$	11.44	$	8.43
(before hedges)
Natural gas per mcf		$	6.74		$	7.13	$	8.03	$	11.22	$	8.23
(including hedges)
Midstream services and marketing
Managed volumes (bpd)			61,590			58,200		61,760		77,100		64,740
(1)Restated - note 3

51

Quarterly table

($ 000s except per unit amounts)	2004(1)
	First Quarter			Second Quarter			Third Quarter			Fourth Quarter		YTD
	Quarter			Quarter			Quarter			Quarter		Total
Financial - consolidated
Revenue	$	234,947		$	218,304		$	287,171		$	369,435	$	1,109,857
Cash flow	$	36,269		$	36,530		$	54,076		$	58,371	$	185,246
Net income (loss)	$	(5,995	)	$	(6,873	)	$	(4,221	)	$	38,314	$	21,225
Net income (loss) per unit - basic and diluted	$	(0.07	)	$	(0.07	)	$	(0.03	)	$	0.27	$	0.19
Unitholder distributions	$	31,036		$	35,039		$	46,489		$	52,064	$	164,628
Distributions per unit	$	0.36		$	0.36		$	0.36		$	0.36	$	1.44
Oil and gas production
Cash revenue	$	54,865		$	59,316		$	89,129		$	91,569	$	294,879
Earnings before interest, DD&A, taxes and other non-cash items	$	30,741		$	34,974		$	51,767		$	50,498	$	167,980
Cash flow	$	26,386		$	29,593		$	44,825		$	41,798	$	142,602
Net income (loss)	$	(9,761	)	$	(10,950	)	$	(17,356	)	$	27,490	$	(10,577	)
Midstream services and marketing
Cash revenue	$	233,031		$	218,388		$	287,679		$	288,768	$	1,027,866
Earnings before interest, DD&A, taxes	$	12,197		$	8,945		$	10,986		$	17,957	$	50,085
and other non-cash items												$
Cash flow	$	9,883		$	6,937		$	9,251		$	16,573		42,644
Net income	$	3,766		$	4,077		$	13,135		$	10,824	$	31,802
Operating
Oil and gas production
Light/medium oil (bpd)		5,965			7,861			12,674			14,012		10,146
Heavy oil (bpd)		6,588			6,537			6,770			6,536		6,608
Natural gas liquids (bpd)		1,130			1,267			1,803			1,770		1,494
Natural gas (mcfd)		63,859			68,007			88,642			87,339		77,022
Oil equivalent (boed)		24,326			27,000			36,021			36,874		31,085
(Cdn $)
Average selling price net of transportation expense
Light/medium oil per bbl
(before hedges)	$	39.00		$	42.28		$	48.59		$	45.83	$	45.01
Light/medium oil per bbl
(including hedges)	$	26.15		$	29.97		$	38.00		$	33.88	$	33.29
Heavy oil per bbl
(before hedges)	$	26.84		$	28.26		$	34.23		$	25.33	$	28.72
Heavy oil per bbl
(including hedges)	$	22.80		$	23.26		$	25.72		$	22.17	$	23.51
Natural gas liquids per barrel	$	37.03		$	40.55		$	40.88		$	42.80	$	40.68
Natural gas per mcf
(before hedges)	$	6.40		$	7.01		$	6.47		$	6.56	$	6.60
Natural gas per mcf
(including hedges)	$	6.31		$	6.26		$	6.05		$	6.31	$	6.23
Midstream services and marketing
Managed volumes (bpd)		67,279			51,393			58,400			52,870		57,484
(1) Restated - note 3

52

PricewaterhouseCoopers LLP

Chartered Accountants

111 5th Avenue SW, Suite 3100

Calgary, Alberta

Canada T2P 5L3

Telephone +1 (403) 509 7500

Facsimile +1 (403) 781 1825

Auditors’ Report

To the Unitholders of Provident Energy Trust

We have audited the consolidated balance sheets of Provident Energy Trustas at December 31, 2005 and 2004 and the consolidated statements of operations and accumulated earnings and cash flows for each of the years ended December 31, 2005 and 2004. These consolidated financial statements are the responsibility of the management of Provident. Our responsibility is to express an opinion on these financial statements based on our audits.

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

In our opinion, these consolidated financial statements present fairly, in all material respects, the financial position of the Trust as at December 31, 2005 and 2004 and the results of its operations and its cash flows for the years ended December 31, 2005 and 2004 in accordance with Canadian generally accepted accounting principles.

Chartered Accountants

Calgary, Alberta

March 3, 2006

Comments by Auditor for U.S. readers on Canada - U.S. reporting differences

In the United States, reporting standards for auditors require the addition of an explanatory paragraph (following the opinion paragraph) when there is change in accounting principles that has a material effect on the comparability of the Trust’s financial statements, such as the changes described in Note 3 and Note 21(i) to the Consolidated Financial Statements. Our report to the Unitholders dated March 3, 2005 is expressed in accordance with Canadian reporting standards which do not require a reference to such a change in accounting principles in the Auditors’ Report when the change is properly accounted for and adequately disclosed in the financial statements.

Chartered Accountants

Calgary, Alberta

March 3, 2006

PricewaterhouseCoopers refers to the Canadian firm of PricewaterhouseCoopers LLP and the other member firms of PricewaterhouseCoopers International Limited, each of which is a separate and independent legal entity.

PROVIDENT ENERGY TRUST
CONSOLIDATED BALANCE SHEETS
Canadian dollars (000s)
		As at		As at
		December 31,		December 31,
		2005		2004
			(restated note 3)
Assets
Current assets
Cash and cash equivalents	$	32,113	$	244
Accounts receivable		267,246		143,142
Petroleum product inventory		110,638		17,151
Deferred derivative loss (note 17)		-		2,144
Prepaid expenses		14,326		10,265
		424,323		172,946
Cash reserve for future site reclamation (note 18)		1,872		1,454
Investments (note 16)		3,758		3,000
Deferred financing charges		14,710		5,584
Property, plant and equipment (note 6)		1,702,689		1,299,654
Intangible assets (note 7)		215,850		-
Goodwill (note 4)		429,068		330,944
	$	2,792,270	$	1,813,582
Liabilities
Current liabilities
Accounts payable and accrued liabilities	$	314,723	$	171,412
Cash distributions payable		20,644		15,416
Distributions payable to non-controlling interests		452		271
Financial derivative instruments		14,149		24,524
		349,968		211,623
Long-term debt - revolving term credit facilities (note 8)		586,597		262,750
Long-term debt - convertible debentures (note 8)		298,007		169,456
Asset retirement obligation (note 10)		41,133		40,506
Future income taxes (note 15)		91,595		70,629
Non-controlling interests
USOGP operations		11,885		13,649
Exchangeable shares (note 11)		8,259		35,921
Unitholders’ equity
Unitholders’ contributions (note 12)		1,971,707		1,438,393
Convertible debentures equity component		19,301		9,785
Contributed surplus (note 13)		1,675		2,002
Cumulative translation adjustment		(41,785)		(28,848)
Accumulated income		97,288		362
Accumulated cash distributions (note 14)		(643,360)		(412,646)
		1,404,826		1,009,048
	$	2,792,270	$	1,813,582

/s/	/s/
Name: Tom Buchanan, CA Title: Director	Name:M.H. (Mike) Shaikh, CA Title: Director

1

PROVIDENT ENERGY TRUST
CONSOLIDATED STATEMENT OF OPERATIONS AND ACCUMULATED INCOME
Canadian dollars (000s except per unit amounts)
	Year ended December 31,
		2005		2004
			(restated note 3)
Revenue (note 9)
Revenue	$	1,419,450	$	1,200,854
Realized loss on financial derivative instruments		(66,860)		(68,944)
Unrealized gain/(loss) on financial derivative instruments		7,684		(22,053)
		1,360,274		1,109,857
Expenses
Cost of goods sold		786,564		741,641
Production, operating and maintenance		171,193		141,493
Transportation		6,932		5,087
Depletion, depreciation and accretion		193,236		177,282
General and administrative		41,608		27,104
Non-cash unit based compensation (note 13)		9,753		1,819
Interest on bank debt		10,875		11,816
Interest and accretion on convertible debentures		19,643		15,173
Amortization of deferred financing charges		1,409		1,435
Foreign exchange gain and other		(3,293)		(2,224)
Loss on redemption of convertible debentures (note 8)		49		-
Gain on sale of assets (note 5)		(5,188)		-
		1,232,781		1,120,626
Income (loss) before taxes and non-controlling interests		127,493		(10,769)
Capital taxes		4,780		5,921
Current and withholding taxes		5,628		1,282
Future income tax expense (recovery) (note 15)		17,793		(40,577)
		28,201		(33,374)
Net income before non-controlling interests		99,292		22,605
Non-controlling interests
USOGP operations		1,596		923
Exchangeable shares (note 11)		770		457
Net income		96,926		21,225
Accumulated income (loss), beginning of year	$	1,844	$	(19,838)
Retroactive application of changes in accounting policies (note 3)		(1,482)		(1,025)
Accumulated income (loss), beginning of year, restated		362		(20,863)
Accumulated income, end of year	$	97,288	$	362
Net income per unit - basic	$	0.61	$	0.19
Net income per unit - diluted	$	0.61	$	0.19

2

PROVIDENT ENERGY TRUST
CONSOLIDATED STATEMENT OF CASH FLOWS
Canadian Dollars (000s)
		Year ended December 31,
		2005		2004
			(restated note 3)
Cash provided by operating activities
Net income for the year	$	96,926	$	21,225
Add (deduct) non-cash items:
Depletion, depreciation and accretion		193,236		177,282
Debenture accretion and amortization of deferred charges		4,090		2,808
Non-cash unit based compensation (note 13)		9,753		1,819
Unrealized (gain) loss on financial derivative instruments (note 9)		(7,684)		22,053
Unrealized foreign exchange gain		(405)		(744)
Future income tax expense (recovery) (note 15)		17,793		(40,577)
Equity in loss of investee		252		-
Net income attributable to non-controlling interests		2,366		1,380
Loss on redemption of convertible debentures (note 8)		49		-
Gain on sale of assets (note 5)		(5,188)		-
Cash flow from operations before changes in working capital and site restoration expenditures		311,188		185,246
Site restoration expenditures (note 18)		(2,481)		(3,219)
Change in non-cash operating working capital		(51,344)		5,796
		257,363		187,823
Cash used for financing activities
Increase (decrease) in long-term debt		325,771		(77,087)
Proceeds of bridge financing		-		158,184
Repayment of bridge financing		-		(158,184)
Declared distributions to unitholders		(230,714)		(164,628)
Declared distributions to non-controlling interest		(3,360)		(964)
Issue of trust units, net of issue costs		395,805		320,976
Issue of debentures, net of costs		239,822		48,000
Redemption of debentures, net of costs		(2,997)		-
Change in non-cash financing working capital		(50)		8,213
		724,277		134,510
Cash used for investing activities
Net capital expenditures		(156,499)		(76,321)
Acquisition of Midstream NGL business (note 4)		(772,303)		-
Acquisition of Nautilus (note 4)		(91,420)		-
Acquisition of Breitburn Energy (note 4)		-		(165,649)
Acquisition of Olympia Energy Inc. (note 4)		-		(4,715)
Acquisition of Viracocha Energy Inc. (note 4)		-		(1,993)
Acquisition of Redwater		-		(1,300)
Acquisition of investment		(1,010)		-
Oil and gas property acquisitions		(586)		(72,745)
Proceeds from property dispositions		45,100		10,717
Proceeds on sale of assets (note 5)		29,295		-
Reclamation fund contributions		(2,899)		(2,844)
Reclamation fund withdrawals		2,481		3,219
Payment of financial derivative instruments		(7,192)		(23,302)
Change in non-cash investing working capital		5,262		12,799
		(949,771)		(322,134)
Increase in cash		31,869		199
Cash and cash equivalents beginning of year		244		45
Cash and cash equivalents end of year	$	32,113	$	244
Supplemental disclosure of cash flow information
Cash interest paid including debenture interest	$	23,946	$	23,619
Cash taxes paid	$	12,026	$	6,483

3

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

(Tabular amounts in Cdn$ 000’s, except unit and per unit amounts)

December 31, 2005

1.            Structure of the Trust

Provident Energy Trust (the “Trust”) is an open-end unincorporated investment trust created under the laws of Alberta pursuant to a trust indenture dated January 25, 2001, amended from time to time. The beneficiaries of the Trust are the unitholders. The Trust was established to hold, directly and indirectly, all types of petroleum and natural gas and energy related assets, including without limitation facilities of any kind, oil sands interests, electricity or power generating assets and pipeline, gathering, processing and transportation assets. The Trust commenced operations March 6, 2001.

Cash flow is provided to the Trust from properties owned and operated by Provident Energy Ltd. and directly and indirectly owned subsidiaries and partnerships of the Trust (“Provident”). Cash flow is paid from Provident to the Trust by way of royalty payments, interest payments and principal repayments. The cash payments received by the Trust are subsequently distributed to the unitholders monthly.

2.            Significant accounting policies

(i)      Principles of consolidation and investments

The consolidated financial statements include the accounts of the Trust and Provident, including the subsidiary Breitburn Energy Company LP (Breitburn), and are presented in accordance with Canadian generally accepted accounting principles. Investments are accounted for using the cost method. Certain comparative numbers have been restated to conform with the current year presentation.

(ii)     Financial derivative instruments

All derivative financial instruments are recorded on the balance sheet at fair value and changes in fair value are recognized in income as unrealized gains or losses on financial derivative instruments in the period in which the change occurs. Actual gains or losses are recorded as realized gains or losses on financial derivative instruments in the period that the instrument is settled.

(iii)   Property, plant & equipment

The Trust follows the full cost method of accounting for oil and natural gas exploration and development activities, whereby all costs associated with the acquisition and development of oil and natural gas reserves are capitalized. Such costs include lease acquisition, lease rentals on non-producing properties, geological and geophysical activities, drilling of productive and non-productive wells, and tangible well equipment. Gains or losses on the disposition of oil and gas properties are not recognized unless the resulting change to the depletion and depreciation rate is 20 percent or more. All other property, plant and equipment, including midstream assets, are recorded at cost. Expenditures relating to renewals or betterments that improve the productive capacity or extend the life of property, plant and equipment are capitalized. Maintenance and repairs are expensed as incurred. Products required to fill in cavern bottoms and pipelines are presented as part of property, plant and equipment and stated at historical cost and are not depreciated.

a)   Depletion, depreciation and accretion

The provision for depletion and depreciation for oil and natural gas assets is calculated using the unit-of-production method based on current production divided by the Trust’s share of estimated total proved oil and natural gas reserve volumes, before royalties. Production and reserves of natural gas and associated liquids are converted at the energy equivalent ratio of 6,000 cubic feet of natural gas to one barrel of oil. In determining its depletion base, the Trust includes estimated future costs for developing proved reserves, and excludes estimated salvage values of tangible equipment and the cost of unproved properties.

4

Midstream facilities, including natural gas liquids storage facilities and natural gas liquids processing and extraction facilities are carried at cost and depreciated on a straight-line basis over the estimated service lives of the assets, which range from 30 to 40 years. Intangible assets are amortized over the estimated useful lives of the assets, which range from two to 15 years. Capital assets related to pipelines are carried at cost and depreciated using the straight-line method over their economic lives.

(b)  Ceiling test

The ceiling test calculation is performed by comparing the carrying value of the cost centre to the sum of the undiscounted proved reserve cash flows expected from the cost centre by country using future price estimates. If the carrying value is not recoverable, the cost centre is written down to its fair value. Fair value is determined by the future cash flows from the proved plus probable reserves discounted at the Trust’s risk free interest rate. Any excess carrying value of the assets on the balance sheet above fair value would be recorded in depletion, depreciation and accretion expense as a permanent impairment.

(iv)     Joint Venture

Provident conducts many of its activities through joint ventures and the accounts reflect only Provident’s proportionate interest in such activities.

(v)      Inventory

Inventories of products are valued at the lower of average cost and net realizable value based on market prices.

(vi)     Goodwill

Goodwill, which represents the excess of cost of an acquired enterprise over the net of the amounts assigned to assets acquired and liabilities assumed, is assessed at least annually for impairment. To assess impairment, the fair value of the reporting unit is determined and compared to the book value of the reporting unit. If the fair value is less than the book value, then a second test is performed to determine the amount of the impairment. The amount of the impairment is determined by deducting the fair value of the reporting unit’s assets and liabilities from the fair value of the reporting unit to determine the implied fair value of goodwill and comparing that amount to the book value of the reporting unit’s goodwill. Any excess of the book value of goodwill over the implied fair value of goodwill is the impaired amount. Goodwill is not amortized.

(vii)    Asset retirement obligation

Under the asset retirement obligation (“ARO”) standard the fair value of a liability for an ARO is recorded in the period where a reasonable estimate of the fair value can be determined. When the liability is recorded, the carrying amount of the related asset is increased by the same amount of the liability. The asset recorded is depleted over the useful life of the asset. Additions to asset retirement obligations due to the passage of time are recorded as accretion expense. Actual expenditures incurred are charged against the obligation.

(viii)   Unit based compensation

The Trust uses the fair value method of valuing compensation expense associated with the Trust’s unit option plan (“the Plan”). Provident has applied this method to options issued after January 1, 2003, the effective date for implementing stock based compensation. Under fair value method the amount to be recognized as expense is determined at the time the options are issued and is deferred and recognized in earnings over the vesting period of the options with a corresponding increase in contributed surplus.

The Trust has established other unit based compensation plans whereby notional units are granted to employees. The fair value of these notional units is estimated and recorded as an expense to non-cash unit based compensation with an offsetting amount to accrued liabilities. A realization of the expense and a resulting reduction in cash provided by operating activities occurs when a cash payment is made.

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(ix)     Trust unit calculations

The Trust applies the treasury stock method to determine the dilutive effect of trust unit rights and trust unit options. Under the treasury stock method, outstanding and exercisable instruments that will have a dilutive effect are included in per unit - diluted calculations, ordered from most dilutive to least dilutive.

The dilutive effect of exchangeable shares and convertible debentures is determined using the "if-converted" method whereby the outstanding exchangeables and debentures at the end of the period are assumed to have been exchanged or converted at the beginnning of the period or at the time of issuance if issued during the year. Amounts charged to income or loss relating to the outstanding exchangeable shares and debentures are added back to net income for the diluted calculation. The units issued upon exchange or conversion are included in the denominator of per unit - basic calculations from the date of issue.

(x)     Future income taxes

Provident follows the liability method for calculating income taxes. Differences between the amounts reported in the financial statements of the corporate subsidiaries and their respective tax bases are applied to tax rates in effect to calculate the future tax liability. The effect of any change in income tax rates is recognized in the current period income.

The Trust is a taxable entity under the Income Tax Act (Canada) and is taxable only on income that is not distributed or distributable to the unitholders. As the Trust distributes all of its taxable income to the unitholders and meets the requirements of the Income Tax Act (Canada) applicable to the Trust, no provision for income taxes has been made in the Trust.

(xi)     Revenue recognition

Revenue associated with the sales of Provident’s natural gas, natural gas liquids (“NGL’s) and crude oil owned by Provident is recognized when title passes from Provident to its customer.

Marketing revenues and purchased product are recorded on a gross basis as Provident takes title to product and has the risks and rewards of ownership.

Revenues associated with the services provided where Provident acts as agent are recorded when the services are provided. Revenues associated with the sale of natural gas liquids storage services are recognized when the services are provided.

(xii)    Use of estimates

The preparation of financial statements requires management to make estimates based on currently available information. In particular, management makes estimates for amounts recorded for depletion and depreciation of the property, plant and equipment, and asset retirement obligation. The ceiling test uses factors such as estimated reserves, production rates, estimated future petroleum and natural gas prices and future costs. Due to the inherent limitations in metering and the physical properties of storage caverns and pipelines, the determination of precise volumes of natural gas liquids held in inventory at such locations is subject to estimation. Actual inventories of natural gas liquids can only be determined by draining of the caverns. By their very nature, these estimates are subject to measurement uncertainty and the effect on the financial statements of future periods could be material.

The estimation of oil and gas reserves is a subjective process. Forecasts are based on engineering data, projected future rates of production, estimated commodity prices, and consider the timing of future expenditures. The Trust expects reserve estimates to be revised based on the results of future drilling activity, testing, production levels, and economics of recovery based on cash flow forecasts.

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3.            Changes in accounting policies and practices

Exchangeable securities - non-controlling interest

Effective June 30, 2005, the Canadian Institute of Chartered Accountants issued an amendment to EIC abstract 151 "Exchangeable Securities Issued by Subsidiaries of Income Trusts" that states that exchangeable securities issued by a subsidiary of an income trust should be reflected as either non-controlling interest or debt on the consolidated balance sheet unless they meet certain criteria. The exchangeable shares issued by Provident Acquisitions Inc. and Provident Energy Ltd. corporate subsidiaries of the Trust are considered under this standard to be transferable to third parties. EIC-151 states that if the exchangeable shares are transferable to a third party, they should be reflected as non-controlling interest. Previously, the exchangeable shares were reflected as a component of unitholders' equity.

As a result of this change in accounting policy, the Trust has reflected non-controlling interest of $8.3 million and $35.9 million, respectively, on the Trust's consolidated balance sheet as at December 31, 2005 and December 31, 2004. Consolidated net income or loss has been adjusted for the earnings attributable to the non-controlling interest of $0.8 million for the year ended December 31, 2005 and $0.5 million for the year ended December 31, 2004. As at June 30, 2005 unitholders' equity was reduced by $11.2 million and non-controlling interest on the consolidated balance sheet increased by $13.0 million. In accordance with the transitional provisions of EIC-151, retroactive application has been applied with restatement of prior periods. The retroactive application of this abstract as at December 31, 2004 was an accumulated loss of $1.5 million. The retroactive accumulated loss adjustments represent the cumulative net income attributable to the non controlling interest for prior periods. Cash flow was not affected by this change.

4.            Acquisitions

(i)     Acquisition of Midstream NGL Assets

On December 13, 2005 Provident acquired midstream business assets (the Midstream NGL Acquisition) from EnCana Corporation by way of the purchase of partnership interests, corporations and assets. The business comprises NGL extraction plants, pipelines, storage and fractionation facilities, distribution facilities, contracts including supply and transportation arrangements, and ownership of Kinetic Resources, two partnerships which perform NGL marketing services including Kinetic’s interests in a distribution terminal and leases on approximately 700 rail cars. The transaction was accounted for using the purchase method with the allocation of the purchase as follows:

Net assets acquired and liabilities assumed
	Property, plant and equipment	$	428,066
	Working capital, net of cash acquired		38,937
	Intangible asset - contracts and customer relationships		183,100
	Intangible asset - fractionation spread support agreement		17,600
	Intangible assets - other		16,308
	Goodwill		98,124
	Financial derivative instruments		945
	Asset retirement obligation		(7,604)
	Future income taxes		(3,173)
		$	772,303
Consideration
	Acquisition costs	$	12,620
	Cash, net of cash acquired		759,683
		$	772,303

The Midstream NGL Acquisition was financed by the issuance of 21,830,000 units at $12.60 per unit and $150 million of 6.5 percent convertible unsecured subordinated debentures. The remaining portion of the purchase price of the Midstream NGL Acquisition was funded through Provident’s credit facility.

7

(ii)   Acquisition of  Nautilus

On March 2, 2005 Provident acquired Nautilus Resources, LLC (“Nautilus”) for cash consideration of $90.2 million and acquisition costs of $1.2 million. Nautilus was a private oil and gas exploration and production company active in Wyoming, USA. The transaction has been accounted for using the purchase method with the allocation of the purchase price as follows:

Net assets acquired and liabilities assumed
	Property, plant and equipment	$	99,877
	Working capital		1,237
	Asset retirement obligation		(1,557)
	Financial derivative instrument		(8,137)
		$	91,420
Consideration
	Acquisition costs	$	1,237
	Cash		90,183
		$	91,420

The result of this acquisition was the non-controlling interest on USOGP operations decreased by 1.4 percent from 5.8 to 4.4 percent.

(iii)   Acquisition of Olympia

On June 1, 2004 Provident acquired Olympia Energy Inc. for consideration of 13,385,579 Trust units with an ascribed value of $152.9 million and 1,325,000 exchangeable shares with an ascribed value of $15.1 million plus acquisition costs which when netted with option proceeds total $4.7 million. Olympia was a public oil and gas exploration and production company active in the Western Canadian sedimentary basin. The transaction has been accounted for using the purchase method with the allocation of the purchase price as follows:

Net assets acquired and liabilities assumed
	Property, plant and equipment	$	162,352
	Goodwill		106,499
	Working capital deficiency		(326)
	Bank debt		(53,852)
	Asset retirement obligation		(1,909)
	Non-hedging derivative instrument		(947)
	Future income taxes		(39,107)
		$	172,710
Consideration
	Acquisition costs	$	8,700
	Option proceeds		(3,985)
	Exchangeable shares issued (note 11)		15,132
	Trust units issued (note 12)		152,863
		$	172,710

(iv)   Acquisition of Viracocha

On June 1, 2004 Provident acquired Viracocha Energy Inc. for consideration of 12,758,386 Trust units with an ascribed value of $145.7 million and 1,325,000 exchangeable shares with an ascribed value of $15.1 million and acquisition costswhich when netted with option proceeds total $2.0 million. Viracocha was a public oil and gas exploration and production company active in the Western Canadian sedimentary basin. The transaction has been accounted for using the purchase method with the allocation of the purchase price as follows:

8

Net assets acquired and liabilities assumed
	Property, plant and equipment	$	109,907
	Goodwill		122,002
	Working capital		2,172
	Bank debt		(49,891)
	Capital lease obligation		(77)
	Deferred lease obligation		(98)
	Asset retirement obligation		(7,895)
	Future income taxes		(13,294)
		$	162,826
Consideration
	Acquisition costs	$	9,000
	Option and warrant proceeds		(7,007)
	Exchangeable shares issued (note 11)		15,132
	Trust units issued (note 12)		145,701
		$	162,826

(v)     Acquisition of Breitburn

On June 15, 2004 Provident acquired 92 percent of Breitburn Energy LLC (Breitburn) for consideration of $157.4 million and acquisition costs of $8.2 million. Breitburn is a private company (now a limited partnership) active in the oil and gas exploitation and production business in the Los Angeles basin, USA. The transaction has been accounted for using the purchase method with the allocation of the purchase price as follows:

Net assets acquired and liabilities assumed
	Property, plant and equipment	$	214,261
	Working capital deficiency		(8,402)
	Non-hedging derivative instruments		(25,181)
	Other assets		1,028
	Asset retirement obligation		(2,367)
	Non-controlling interest		(13,690)
		$	165,649
Consideration
	Acquisition costs	$	8,214
	Cash		157,435
		$	165,649

On October 4, 2004, the Trust funded Breitburn $58.5 million (US $45 million) for the Orcutt property acquisition.

 5.  Sale of assets

On May 1, 2005, certain oil purchase and sale contracts were sold for net proceeds of $5.5 million and a gain recorded of $5.2 million net of disposal costs.

On December 29, 2005, a parcel of land in California was sold for net proceeds of $23.8 million. The sale represents surface rights for real estate development, with no impact on oil and gas reserves. The transaction resulted in a deferred gain of $1.0 million. The purchaser has agreed to complete the removal and relocation of oilfield infrastructure and environmental remediation work. Not included in the net proceeds or deferred gain is contingent proceeds, amounting to $2.7 million, which are held in escrow until this work is completed.

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 6.  Property, plant and equipment

December 31, 2005		Cost		Accumulated depletion and depreciation		Net Book value
Oil and natural gas properties	$	1,710,998	$	731,336	$	979,662
Midstream assets		738,835		21,951		716,884
Office equipment		12,423		6,280		6,143
Total	$	2,462,256	$	759,567	$	1,702,689
December 31, 2004		Cost		Accumulated depletion and depreciation		Net Book value
Oil and natural gas properties	$	1,567,902	$	555,280	$	1,012,622
Midstream assets		293,616		11,815		281,801
Office equipment		9,904		4,673		5,231
Total	$	1,871,422	$	571,768	$	1,299,654

Costs associated with unproved properties excluded from costs subject to depletion as at December 31, 2005 totaled $23.8 million (December 31, 2004 - $31.2 million). Asset retirement costs of $38.6 million are included in the property, plant and equipment (December 31, 2004 - $36.0 million).

An impairment test calculation was performed on property, plant and equipment at December 31, 2005 in which the estimated undiscounted future net cash flows based on estimated future prices associated with the proved reserves exceeded the carrying amount of oil and gas property, plant and equipment.

The following table outlines prices used in the impairment test at December 31, 2005:

	Oil			Gas			NGL
Year	$/bbl			$/mcf			$/bbl
2006	$	44.50		$	10.11		$	48.35
2007	$	44.25		$	8.77		$	46.86
2008	$	45.20		$	7.86		$	46.47
2009	$	45.17		$	7.53		$	44.96
2010	$	43.99		$	7.19		$	43.31
Thereafter (1)		2.00	%		2.00	%		2.00	%
(1) Percentage change represents the increase in each year after 2010 to the end of the reserve life.

7.            Intangible assets

The intangible assets were acquired as part of the Midstream NGL Acquisition (note 4).

December 31, 2005	Cost		Accumulated amortization		Net Book value
Midstream and marketing contracts and customer relationships	$	183,100	$	635	$	182,465
Fractionation spread support agreement		17,600		458		17,142
Other intangible assets		16,308		65		16,243
Total	$	217,008	$	1,158	$	215,850

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8.           Long-term debt

		December 31, 2005		December 31, 2004
Revolving term credit facilities	$	586,597	$	262,750
Convertible debentures		298,007		169,456
	$	884,604	$	432,206

(i)    Revolving term credit facilities

Provident has a $750 million term credit facility with a syndicate of Canadian chartered banks secured by its Canadian oil and gas properties and all of its midstream assets. Provident may draw on the credit facility by way of Canadian prime rate loans, U.S. base rate loans, banker’s acceptances, letters of credit or LIBOR loans. At December 31, 2004 the facility totaled $410 million. In July 2005 the facility was increased to $450 million. In October, the facility was increased to its current level of $750 million. At December 31, 2005, $544.1 million was drawn on this facility.

Pursuant to the terms of the facility agreement, each year on or after May 30, Provident can request the revolving period to be extended for a further 364-day period. If the lenders do not extend the revolving period, at Provident’s option, the credit facility is converted to a two year non-revolving term credit facility at the end of the 364 day term, with 25% of the loan balance due 12 months after the date of the commencement of the non-revolving term credit, 25% due 18 months after the date of the commencement of the non-revolving term credit, and the remainder of the unpaid balance due on the maturity date.

In July 2005, Provident added a credit facility with a borrowing base of US $100 million with a syndicate of U.S. banks secured by oil and gas assets of Breitburn. Provident may draw upon the facility by way of U.S. base rate loans, libor loans or letters of credit. The facility has a termination date of July 11, 2009 and the current borrowing base is reviewed every six month period commencing June 1, 2006 and each subsequent December 1 and June 1 thereafter. At December 31, 2005, $42.5 million was drawn on this facility.

At December 31, 2005 the effective interest rate of the outstanding credit facilities was 4.6 percent (2004 - 4.3 percent). At December 31, 2005 Provident had $45.1 million in letters of credit outstanding (2004 - $31 million) that guarantee Provident’s performance under certain commercial and other contracts.

(ii)    Convertible debentures

On November 15, 2005 the Trust issued $150.0 million of unsecured convertible subordinated debentures ($143.8 million net of issue costs) with a 6.5 percent coupon rate maturing April 30, 2011. Issue costs have been classified as deferred financing charges. The debentures may be converted into trust units at the option of the holder at a conversion price of $14.75 per trust unit prior to April 30, 2011 and may be redeemed by the Trust under certain circumstances. The unsecured subordinated convertible debentures were initially recorded at fair value of $141.4 million. The difference between the fair value and proceeds of $8.6 million was recorded as equity.

On May 31, 2005 the Trust completed the redemption of its 10.5 percent convertible unsecured subordinated debentures that were originally scheduled to mature May 15, 2007. A total of 3.5 million units were issued at the conversion price of $10.70 per unit. A further $3.0 million cash was paid to the remaining debenture holders that did not convert to trust units at $1,050 for each $1,000 of convertible debenture held plus accrued interest to May 31, 2005 resulting in a loss on redemption of $49,000. Unamortized deferred debt issue costs of $2.5 million, originally incurred on the issuance of the 10.5 percent convertible debentures, were reclassified to trust unit issue costs as a result of the issuance of 3.5 million trust units.

On March 1, 2005 the Trust issued $100.0 million of unsecured convertible subordinated debentures ($95.8 million net of issue costs) with a 6.5 percent coupon rate maturing August 31, 2012. Issue costs have been classified as deferred financing charges. The debentures may be converted into trust units at the option of the holder at a conversion price of $13.75 per trust unit prior to August 31, 2012 and may

11

be redeemed by the Trust under certain circumstances. The unsecured subordinated convertible debentures were initially recorded at fair value of $92.6 million. The difference between the fair value and proceeds of $7.4 million was recorded as equity.

On July 6, 2004 the Trust issued $50.0 million of unsecured subordinated convertible debentures ($48.0 million net of issue costs) with an 8.0 percent coupon rate maturing July 31, 2009. Issue costs have been classified as deferred financing charges. The debentures may be converted into trust units at the option of the holder at a conversion price of $12.00 per trust unit prior to July 31, 2009, and may be redeemed by the Trust under certain circumstances.

The Trust may elect to satisfy interest and principal obligations by the issuance of trust units. During 2005, $109.3million (2004- $0.12 million) of the face value of debentures were converted to trust units, $63.6 million at the election of debenture holders and $45.7 million associated with the May 31, 2005 redemption.

		December 31, 2005				December 31, 2004
Convertible Debentures
($ 000s except conversion pricing)		Carrying Value (1)		Face Value		Carrying Value (1)		Face Value	Maturity Date	Conversion Price per unit (2)
10.5% Convertible Debentures	$	-	$	-	$	49,423	$	49,881	May 15, 2007	10.70
6.5% Convertible Debentures		141,522		150,000		-		-	April 30, 2011	14.75
6.5% Convertible Debentures		92,482		99,179		-		-	Aug. 31, 2012	13.75
8.0% Convertible Debentures		32,382		33,648		48,199		50,000	July 31, 2009	12.00
8.75% Convertible Debentures		31,621		32,659		71,834		74,930	Dec. 31, 2008	11.05
	$	298,007	$	315,486	$	169,456	$	174,811
(1) Excluding equity component of convertible debentures
(2) The debentures may be converted into trust units at the option of the holder of the debenture at the conversion price
per unit

9.            Revenue

		Year ended December 31,
Year ended December 31,		2005		2004
Gross production revenue	$	621,761	$	449,869
Product sales and service revenue		908,111		840,184
Royalties		(110,422)		(89,199)
Revenue	$	1,419,450	$	1,200,854
Realized loss on financial derivative instruments		(66,860)		(68,944)
Unrealized gain (loss) on financial derivative instruments		7,684		(22,053)
	$	1,360,274	$	1,109,857
Change in unrealized loss on financial derivative instruments	$	9,828	$	937
Amortization of loss on financial derivative instruments		(2,144)		(22,990)
Unrealized gain (loss) on financial derivative instruments	$	7,684	$	(22,053)

The realized loss on financial derivative instruments for the year ended December 31, 2005 of $66.9 million (2004 - $68.9 million) relates to the cash settlement on derivative instruments.

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 10.    Asset retirement obligation

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

The total undiscounted amount of future cash flows required to settle asset retirement obligations related to oil and gas operations is estimated to be $293.0 million. Payments to settle oil and gas asset retirement obligations occur over the operating lives of the assets estimated to be from two to 50 years.

The total undiscounted amount of future cash flows required to settle the midstream services and marketing asset retirement obligations is estimated to be $179.3 million. The estimated costs include such activities as dismantling, demolition and disposal of the facilities as well as remediation and restoration of the surface land. Payments to settle the midstream services and marketing asset retirement obligations are expected to occur subsequent to the closure of the facilities and related assets. Settlement of these obligations is expected to occur in 30 to 45 years.

		Year ended December 31,
($000s)		2005		2004
Carrying amount, beginning of year	$	40,506	$	33,182
Business acquisitions		9,161		12,171
Change in estimate		2,884		(2,429)
Increase in liabilities incurred during the period		1,784		166
Settlement of liabilities during the period		(2,614)		(4,971)
Decrease in liabilities due to disposition		(13,612)		-
Accretion of liability		3,024		2,387
Carrying amount, end of year	$	41,133	$	40,506

 11.    Exchangeable shares - non-controlling interest

The Trust retroactively applied EIC-151 “Exchangeable Securities Issued by a Subsidiary of an Income Trust” as at June 30, 2005. The non-controlling interest on the consolidated balance sheet consists of the fair value of the exchangeable shares upon issuance plus the accumulated earnings attributable to the non-controlling interest. The net income attributable to the non-controlling interest on the consolidated statement of operations represents the cumulative share of net income attributable to the non-controlling interest based on the trust units issuable for exchangeable shares in proportion to total trust units issued and issuable at each quarter end during the year.

On June 1, 2004 2.65 million exchangeable shares of Provident Energy Ltd. were issued pursuant to the acquisition transactions for Olympia Energy Inc. and Viracocha Energy Inc. The Exchangeable Shares will be automatically exchanged for Trust Units on January 15, 2006, subject to extension at the option of the issuer. The exchange ratio for these shares is calculated with reference to the distributions.

Following is a summary of the non-controlling interest - exchangeable shares for years ended December 31, 2005 and 2004:

Year ended December 31,		2005		2004
Non-controlling interest, beginning of year	$	35,921	$	20,543
Exchangeable shares issued		-		30,264
Reduction of book value for conversion to trust units		(28,432)		(15,343)
Net income attributable to non-controlling interest		770		457
Non-controlling interest, end of year	$	8,259	$	35,921
Accumulated income attributable to non-controlling interest	$	2,252	$	1,482

13

The following table details the number of exchangeable shares converted and outstanding in addition to the associated book value:

	Year ended December 31,
	2005			2004
Exchangeable shares
Provident Acquisitions Inc.	Number of units		Amount (000s)	Number of units		Amount (000s)
Balance at beginning of year	336,876	$	3,675	534,357	$	5,829
Converted to trust units	(336,876)		(3,675)	(197,481)		(2,154)
Balance, end of year	-		-	336,876		3,675
Exchange ratio, end of year	-		-	1.42501		-
Trust units issuable upon conversion, end of year	-	$	-	480,052	$	3,675
Exchangeable shares
Provident Energy Ltd.*
Balance at beginning of year	638,474	$	6,833	1,279,227	$	13,689
Converted to trust units	(174,929)		(1,872)	(640,753)		(6,856)
Balance, end of year	463,545		4,961	638,474		6,833
Exchange ratio, end of year	1.50962		-	1.35099		-
Trust units issuable upon conversion, end of year	699,777	$	4,961	862,572	$	6,833
Exchangeable shares (Series B) Provident Energy Ltd.**
Balance at beginning of year	2,095,271	$	23,931	-	$	-
Issued to acquire Olympia Energy Inc.	-		-	1,325,000		15,132
Issued to acquire Viracocha Energy Inc.	-		-	1,325,000		15,132
Converted to trust units	(2,003,951)		(22,885)	(554,729)		(6,333)
Balance, end of year	91,320		1,046	2,095,271		23,931
Exchange ratio, end of year	1.19311		-	1.06742		-
Trust units issuable upon conversion, end of year	108,955	$	1,046	2,236,534	$	23,931
Total Trust units issuable upon conversion
of all exchangeable shares, end of year	808,732	$	6,007	3,579,158	$	34,439
* Maturity date is June 30, 2006
**Maturity date is January 15, 2006.

 12.    Unitholders’ contributions

The Trust has authorized capital of an unlimited number of common voting trust units.

Trust units are redeemable at any time on demand by the holders thereof. Upon receipt of a redemption request by the Trust, the holder is entitled to receive a price per trust unit (the “Market Redemption Price”) equal to the lesser of: (i) 90% of the simple average of the closing price of the trust units on the principal market on which the trust units are quoted for trading during the 10 trading day period commencing immediately after the date on which the trust units are surrendered for redemption; and (ii) the closing market price on the principal market on which the trust units are quoted for trading on the date that the trust units are surrendered for redemption.

The aggregate Market Redemption Price payable by the Trust in respect of any trust units surrendered for redemption during any calendar month shall be satisfied by way of a cash payment on the last day of the following month. Total cash payments for redemption are limited to an annual maximum of $250,000. Any excess over the maximum may be satisfied by distributing notes having an aggregate principal amount equal to the aggregate Market Redemption Price of the trust units tendered for redemption.

14

(i)                     2005 activity

On March 1, 2005 the Trust issued 8.4 million units at $12.00 per unit for proceeds of $100.8 million ($95.6 million net of issue costs) pursuant to a February 18, 2005 public offering.

On November 15, 2005 the Trust issued 21.83 million Subscription Receipts at a price of $12.60 per Subscription Receipt for total proceeds of $275.1 million ($261.0 million net of issue costs). Each Subscription Receipt entitled the holder to receive one trust unit upon completion of the Midstream NGL Acquisition. The acquisition closed on December 13, 2005 at which time all of the outstanding Subscription Receipts were converted to trust units. At that time, the holders of the Subscription Receipts were also entitled to $0.12 per trust unit, which is the equivalent of the November distribution paid in December. This payment was treated as a reduction to the proceeds received for the units issued through the Subscription Receipts to $12.48 per trust unit, reducing the amount attributed to Unitholders’ contributions by $2.6 million. Proceeds from the issue were used to fund the Midstream NGL Acquisition.

In 2005 the Trust issued 16.3million units related to Provident’s DRIP program, conversion of exchangeable shares to units, conversion and redemption of convertible debentures to units and units issued pursuant to Provident’s Unit Option Plan. The net increase in unitholders’ contributions associated with these activities was $181.8million.

(ii)                     2004 activity

On February 4, 2004 the Trust issued 4.5 million units at $11.20 per unit for proceeds of $50.4 million ($47.9 million net of issue costs) pursuant to a January 22, 2004 public offering. Proceeds from the issue were initially used to pay down Provident’s bank debt and throughout 2004 were used to finance the 2004 capital program.

On June 1, 2004 the Trust issued 13.4 million units (at an ascribed value of $152.9) and a further 12.8 million units (at an ascribed value of $145.7 million) as part of the consideration to acquire the outstanding shares of Olympia Energy Inc. and Viracocha Energy Inc. respectively.

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

On October 4, 2004 the Trust issued 11.48 million units at $10.95 per unit, for net proceeds (after underwriters’ fees) of $119.4 million. Proceeds were used to fund the acquisition of the Orcutt property in California ($57.3 million) and to repay bank debt.

In 2004 the Trust issued 4.2 million units related to Provident’s DRIP program, conversion of exchangeable shares to units, conversion of convertible debentures to units and units issued pursuant to Provident’s Unit Option Plan. The net increase in unitholders’ contributions associated with these activities was $40.0 million.

	Year ended December 31,
	2005			2004
Trust Units	Number of units		Amount (000s)	Number of units		Amount (000s)
Balance at beginning of year	142,226,248	$	1,438,393	82,824,688	$	803,299
Issued to acquire Olympia Energy Inc. (note 4)	-		-	13,385,579		152,863
Issued to acquire Viracocha Energy Ltd. (note 4)	-		-	12,758,386		145,701
Issued for cash	30,230,000		373,238	29,080,000		312,346
Exchangeable share conversions	2,971,217		28,432	1,633,312		15,343
Issued pursuant to unit option plan	2,265,179		23,435	638,991		4,677
Issued pursuant to the distribution reinvestment plan	1,330,156		16,438	1,745,418		18,250
To be issued pursuant to the distribution reinvestment plan	107,000		2,005	148,496		1,616
Debenture conversions	6,135,418		64,808	11,378		124
Redemption of the 10.5% debentures (note 8)	3,507,570		46,707	-		-
Unit issue costs	-		(21,749)	-		(15,826)
Balance at end of year	188,772,788	$	1,971,707	142,226,248	$	1,438,393

15

The basic per trust unit amounts for 2005 were calculated based on the weighted average number of units outstanding of 159,315,847 which excludes the shares exchangeable into trust units (2004 - 113,310,002). The diluted per trust unit amounts for 2005 are calculated including an additional 369,566 trust units (2004 - 179,428) for the effect of the unit option plan. Provident’s convertible debentures and exchangeable shares are not included in the computation of diluted earnings per unit as their effect is anti-dilutive.

13.           Non-cash unit based compensation

(i)    Unit option plan

The Trust option plan (the “Plan”) is administered by the Board of Directors of Provident. Under the Plan, all directors, officers and employees of Provident, are eligible to participate in the Plan. There are 8,000,000 trust units reserved for the Trust option plan. Options are granted at a “strike price” which is not less than the closing price of the units on the Toronto Stock Exchange on the last trading day preceding the grant. In certain circumstances, based upon the cash distributions made on the trust units, the strike price may be reduced at the time of exercise of the option at the discretion of the option holder. Options vest six months after grant and every year thereafter in equal increments. In October 2005, a restricted/performance unit program (see (iii)) was approved. This program replaces the unit option plan. Unit options in existence will continue to be outstanding.

Year ended December 31,	2005		2004
	Number of Options	Weighted Average  Exercise Price	Number of Options	Weighted Average Exercise Price
Outstanding, beginning of year	5,200,331	$11.01	4,008,744	$11.06
Granted	296,200	11.73	1,909,067	10.89
Exercised	(2,265,179)	10.97	(638,991)	10.96
Forfeited	(25,727)	10.97	(78,489)	11.25
Outstanding, end of year	3,205,625	11.11	5,200,331	11.01
Exercisable, end of year	2,206,801	$11.12	2,620,941	$11.05

At December 31, 2005, the Trust had 3,205,625 options outstanding with strike prices ranging between $8.91 and $12.14 per unit. The weighted average remaining contractual life of the options is 2.20 years and the weighted average exercise price is $11.11 per unit excluding average potential reductions to the strike prices of $1.16 per unit.

At December 31, 2004, the Trust had 5,200,331 options outstanding with strike prices ranging from $8.40 and $12.39 per unit. The weighted average remaining contractual life of the options was 2.71 years and the weighted average exercise price was $11.01 per unit excluding average potential reductions to the strike prices of $1.08 per unit.

On December 31, 2004 the Trust prospectively applied the fair value based method of accounting for the Plan. Previously, the Trust applied the intrinsic value methodology due to the uncertainties of future expected distributions. The Trust now uses the Black-Scholes option-pricing model to calculate the estimated fair value of the outstanding options issued on or after January 1, 2003 at their issue date. The Trust has reevaluated the assumptions required to calculate the fair value of options and considers the estimates required to calculate the fair value reasonably estimated at the time of the issue of the options.

In 2005 the Trust recorded non-cash unit based compensation expense of $1.1 million, for the 5.6 million options granted on or after January 1, 2003 (2004 - $1.0 million).

As at December 31, 2005, the following assumptions are the weighted averages of the individual assumptions applied at each grant date to arrive at an estimate of fair value of all granted options on or after January 1, 2003 of $3.8million:

16

	2005 Granted Options	2004 Granted Options	2003 Granted Options
Expected annual dividend	8.00%	8.00%	8.00%
Expected volatility	19.88%	20.18%	19.46%
Risk - free interest rate	3.26%	3.30%	3.66%
Expected life of option (yrs)	3.31	3.31	3.31
Expected forfeitures	-	-	-
Fair Value of Granted Options	$0.2 million	$1.2 million	$2.4 million

The remaining fair value of the rights of $0.4 million, less any future cancellations, will be recognized in earnings over the remaining vesting period of the rights outstanding. The following table reconciles the movement in the contributed surplus balance.

Year ended December 31,		2005		2004
Contributed surplus, beginning of the year	$	2,002	$	1,305
Compensation expense		1,055		1,190
Benefit on options exercised charged to unitholders’ equity		(1,382)		(493)
Contributed surplus, end of year	$	1,675	$	2,002

(ii)    Restricted/Performance Units

In May 2005 the board of directors approved a program whereby certain employees of the Trust’s Canadian subsidiaries will be granted restricted trust units (RTU’s) and/or performance trust units (PTU’s), both of which entitle the employee to receive cash compensation in relation to the value of a specified number of underlying notional trust units. The grants are based on criteria designed to recognize the long term value of the employee to the organization. This plan replaces the unit options plan for 2005 and subsequent years. RTU’s vest evenly over a period of three years commencing one year after grant. Payments are made on the anniversary dates of the RTU to the employees entitled to receive them on the basis of a cash payment equal to the value of the underlying notional units. PTU’s vest three years from the date of grant and can be increased to a maximum of double the PTU’s granted or a minimum of nil PTU’s depending on the Trust’s performance vis-à-vis other trusts’ performance based on certain benchmarks.

As of December 31, 2005 there were 226,055 RTU’s and 464,291 PTU’s outstanding. The fair value estimate associated with the RTU’s and PTU’s is expensed in the statement of income over the vesting period. During the year ended December 31, 2005, the Trust recorded compensation costs of $2.6 million with respect to the expected issue of RTU’s and PTU’s (2004 - nil).

(iii)   Unit appreciation rights

During 2004, the Trust put in place a program whereby certain employees of its U.S. subsidiary are granted unit appreciation rights (“UAR’s”) which entitle the employee to receive cash compensation in relation to the value of a specified number of underlying notional trust units. UAR’s vest evenly over a period of three years commencing one year after grant and expire after four years.

The UAR’s, upon vesting, provide certain employees entitlement to receive a cash payment equal to the excess of the market price of the Trust’s Units over the exercise price of the right less notionally accrued distributions in excess of an eight percent return. These prices are denominated in US dollars and are based on quoted US distributions and market prices.

The following table summarizes the information about UAR’s:

17

	2005				2004
	Number of Units Appreciation Rights		Weighted Average Exercise Price (US$)		Number of Units Appreciation Rights		Weighted Average Exercise Price (US$)
Year ended December 31,
Outstanding, beginning of year		976,000	$	7.98		-	$	-
Granted		147,000		10.01		976,000		7.98
Exercised		(296,641)		7.91		-
Forfeited		(57,666)		8.79		-
Outstanding, end of year		768,693	$	8.34		976,000	$	7.98
Exerciseable, end of year		22,704		8.92		-		-
Weighted average remaining contract life (years)		2.58				3.48
Average potential reductions to exercise price		$0.71				$0.29

The fair value associated with the UAR’s is expensed in the statement of income over the vesting period. During the year, the Trust recorded compensation costs of $2.2 million related to the outstanding UAR’s (2004 - $0.4 million). Cash payments of $1.0 million (2004 - nil) were recorded against general and administrative expense resulting in $1.2 million (2004 - $0.4 million) recorded as non-cash unit based compensation.

(iv)   Other unit based compensation

Pursuant to employment agreements between Breitburn and certain employees, the employees are eligible to receive cash compensation in relation to the value of a specified number of underlying notional units. The value of each notional unit is determined on the basis of a valuation of Breitburn as at the end of the fiscal period. At December 31, 2005 there were 2,200,000 notional units outstanding under the key employee plan (2004 - 2,200,000) which vest one third three years after grant date, one third four years after grant date and one third five years after grant date. All units under this plan were granted in 2004. There were 4,155,290 notional units outstanding under the phantom unit plan (2004 - 3,000,000) of which all notional units vest immediately and are payable 90 days from the fiscal year-end. For the period ended December 31, 2005 compensation expense of $6.2 million was recorded under the plans (2004 - $0.4 million). Cash payments of $1.3 million (2004 - nil) were recorded against general and administrative expense resulting in $4.9 million (2004 - $0.4 million) recorded as non-cash unit based compensation.

14.           Reconciliation of cash flow and distributions

		Year ended December 31,
		2005		2004
Cash provided by operating activities	$	257,363	$	187,823
Change in non-cash operating working capital		51,344		(5,796)
Site restoration expenditures		2,481		3,219
Cash flow from operations		311,188		185,246
Cash reserved for financing and investing activities		(80,474)		(20,618)
Cash distributions to unitholders		230,714		164,628
Accumulated cash distributions, beginning of period		412,646		248,018
Accumulated cash distributions, paid and declared, end of period	$	643,360	$	412,646
Cash distributions per unit	$	1.44	$	1.44

Cash reserved for financing and investing activities is a discretionary amount and represents the difference between cash flow from operations less distributions.

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15.    Future income taxes 

Provident follows the liability method for calculating future income taxes. Under this method, future income tax assets and liabilities are recognized based on the estimated tax effects of temporary differences in the carrying value of assets and liabilities, reported in the financial statements of the corporate subsidiaries, and their respective tax bases, using income tax rates substantively enacted on the consolidated balance sheet date:

	Year ended December 31,
		2005		2004
Petroleum and natural gas properties, production facilities and other	$	89,607	$	70,301
Midstream facilities		1,988		328
	$	91,595	$	70,629

The future income tax provision differs from the expected amount calculated by applying the Canadian combined federal and provincial income tax rate of 37.82 percent (2004 - 38.87 percent) as follows:

		Year ended December 31,
		2005		2004
Expected income tax expense (recovery)	$	48,218	$	(4,186)
Increase (decrease) resulting from:
Non-deductible Crown charges and other payments		14,285		17,087
Federal resource allowance		(11,489)		(7,535)
Alberta Royalty Tax Credit		(188)		(194)
Income of the Trust and other		(32,567)		(41,336)
Capital Taxes		4,780		5,921
Witholding tax and other		5,628		1,282
Income tax rate changes		(466)		(4,413)
	$	28,201	$	(33,374)

16.    Related party transactions

On December 30, 2004, at the conclusion of a competitive process, Provident sold properties to a private company on whose board two of the directors of Provident sit and in which they own shares. The properties were sold for consideration of $3.5 million of which $0.5 million was cash and $3.0 million consisted of 10,000,000 common shares valued at $0.30 per share. The carrying value of these shares is included in investments on the balance sheet. The transaction was recorded at fair value.

17.    Financial instruments and hedging

Financial instruments of the Trust carried on the consolidated balance sheet consist mainly of cash and cash equivalents, accounts receivable, reclamation fund investments, current liabilities, other long-term liabilities, asset retirement obligations, commodity and foreign currency contracts and long-term debt. Except as noted below, as at December 31, 2005 and 2004, there were no significant differences between the carrying value of these financial instruments and their estimated fair value.

Substantially all of the Trust's accounts receivable are due from customers and joint venture partners in the oil and gas and midstream services and marketing industries and are subject to credit risk. The Trust partially mitigates associated credit risk by limiting transactions with certain counterparties to limits imposed by the Trust based on the Trust’s assessment of the creditworthiness of such counterparties. The carrying value of accounts receivable reflects management's assessment of the associated credit risks. With respect to counterparties to financial instruments, the Trust partially mitigates associated credit risk by limiting transactions to counterparties with investment grade credit ratings and obtaining financial guarantees from certain counterparties.

19

At January 1, 2004 the Trust adopted CICA accounting guideline 13 “Hedging relationships” resulting in the recognition of an unrealized loss of $25.1 million in deferred charges on the consolidated balance sheet that has been amortized to income over the same period as the corresponding losses associated with the hedged items.

Year ended December 31,		2005			2004
Deferred derivative Loss
Non-hedging derivative liability, beginning of year	$	2,144		$	25,134
Derivative instruments amortized		(2,144	)		(22,990	)
Deferred derivative loss, end of year	$	-		$	2,144

Provident’s commodity price risk management program is intended to minimize the volatility of commodity prices and to assist with stabilizing cash flow and distributions. Provident seeks to accomplish this through the use of financial instruments from time to time to reduce its exposure to fluctuations in commodity prices and foreign exchange rates.

With respect to financial instruments, Provident could be exposed to losses if a counterparty fails to perform in accordance with the terms of the contract. This risk is managed by diversifying the derivative portfolio among counterparties meeting certain financial criteria.

(i)             Commodity price

a)   Crude oil

For 2005, Provident paid out $59.0 million to settle various oil market based contracts on an aggregate volume of 2.6 million barrels. For 2004, Provident paid out $55.3 million to settle various oil market based contracts on an aggregate volume of 2.7 million barrels. The estimated value of contracts in place if settled at market prices at December 31, 2005 would have resulted in an opportunity cost of $7.1 million (2004 -$25.2 million).

b)   Natural Gas

For 2005, Provident paid $5.6 million to settle various natural gas market based contracts on an aggregate of 5.2 million gigajoules (“GJ”). For 2004, Provident paid $10.4 million to settle various natural gas market based contracts on an aggregate of 10.9 million gigajoules (“GJ”). The estimated value of contracts in place if settled at market prices at December 31, 2005 would have resulted in an opportunity cost of $6.5 million (2004 - an opportunity gain of $0.3 million).

c)   Midstream

For 2005, Provident paid $2.3 million (2004 - $3.2 million) to settle various midstream contracts, that were entered into to fix prices on product sales. The estimated value of contracts in place if settled at market prices as December 31, 2005 would have resulted in an opportunity cost of $0.4 million (2004 - opportunity gain of $0.2 million).

(ii)         Foreign exchange contracts

The estimated value of contracts in place if settled at foreign exchange rates at December 31, 2005 would have resulted in an opportunity cost of $0.1 million (2004 - opportunity gain of $0.2 million). The foreign exchange gains have been included in note 20 as component of foreign exchange gain and other and allocated to their respective business segments.

20

The contracts in place at December 31, 2005 are summarized in the following tables:

COGP
Year	Product	Volume (Buy)Sell		Terms	Effective Period
2006	Crude Oil	750	Bpd	Participating Swaps US $51.33 per bbl (63% above floor price) (1) (3)	January 1 - December 31
		500	Bpd	Participating Swaps US $48.00 per bbl (max to 90% above floor price) (3)	January 1 - December 31
		750	Bpd	Puts US $53.33 per bbl (1)	January 1 - Decmeber 31
	Natural Gas (2)	10,000	Gjpd	Participating Swaps Cdn $8.00 per gj (max to 90% above floor price) (1) (3)	January 1 - March 31
		8,500	Gjpd	Participating Swaps Cdn $7.32 per gj (max to 90% above floor price) (1) (3)	January 1 - December 31
		5,000	Gjpd	Participating Swaps Cdn $6.75 per gj (max to 87% above floor price) (3)	April 1 - October 31
		5,000	Gjpd	Participating Swaps Cdn $7.00 per gj (max to 85% above floor price) (3)	April 1 - December 31
	Foreign Exchange			Sell US $2,000,000 at 1.165 (4)	January 25

USOGP (Breitburn)
Year	Product	Volume (Buy)Sell		Terms	Effective Period
2006	Crude Oil	1,000	Bpd	Participating Swap US $47.25 per bbl (65% above floor price) (1) (3)	January 1 - December 31
		1,000	Bpd	Puts US $53.00 per bbl (1)	January 1 - December 31

Midstream
Year	Product	Volume (Buy)Sell		Terms	Effective Period
2006	Propane	19,600	Gpd	Purchased Calls US $0.95 per gal (8)	January 1 - April 30
		13,017	Gpd	Sold Put US $0.82 per gal (1) (8)	January 1 - February 28
		4,500	Gpd	Sold Put US $0.84 per gal (8)	February 1 -February 28
		1,899	Gpd	Sold Put US $0.90 per gal (8)	January 1 - March 31
		33,871	Gpd	Sold Call US $1.07 per gal (8)	Janury 1 - January 31
		17,733	Gpd	Sold Call US $0.95 per gal (8)	January 1 - April 30
		14,237	Gpd	US $0.81 per usg (8)	January 1 - February 28
		135,263	Gpd	US $0.972 per usg (1) (8)	January 1 - March 31
		2,333	Gpd	US $0.875 per usg (8)	January 1 - April 30
	Crude Oil	375	Bpd	US $61.70 per bbl (6)	January 1 - March 31
	Natural Gas	(6,350)	Gjpd	Cdn $11.08 per gj (2)	January 1 - March 31
		4,000	Gjpd	Cdn $13.75 per gj (2) (7)	January 1 - January 31
		(4,000)	Gjpd	Cdn $12.75 per gj (2) (7)	January 1 - January 31
		400,000	Mmbtu	US $14.25 per mmbtu (10)	February 1 - February 28
	Foreign Exchange			Sell US $6,259,039 at 1.1753 (5)	January 1 - March 31
2010	Crude Oil	250	Bpd	Costless collar US $54.00 floor, US $61.05 ceiling (9)	January 1 - December 31
	Natural Gas	(1,342)	Gjpd	Cdn $6.97 per gj (2)	January 1 - December 31
	Foreign Exchange			Sell US $4,927,500 at 1.1185 (5)	January 1 - December 31
(1) Represents a number of transactions entered into over an extended period of time.
(2) Settled against AECO monthly index.
(3) Provides a floor price while allowing percentage participation above strike price.
(4) US dollar cashflow.
(5) Foreign exchange contracts to hedge underlying exchange rate on Cdn cashflow.
(6) Condensate & Butane hedged using WTI monthly calendar average as proxy.
(7) Ethane hedged using AECO monthly index as proxy.
(8) Transactions entered into by Kinetic Resources prior to acquisition by Provident.
(9) Propane, Butane and Condensate hedged using WTI monthly calendar average as proxy.
(10) Settled against NYMEX Henry Hub Natural Gas futures contract.
(11) Offsetting trades have not been included in the table.

21

18.    Cash reserve for future site reclamation

Provident established a cash reserve effective May 1, 2001 for future site reclamation expenditures relating to its Canadian oil and gas production. In accordance with the royalty agreement, Provident funds the reserve by paying $0.30 per barrel of oil equivalent produced on a 6:1 basis into a segregated cash account. Actual expenditures incurred are then funded from the cash in this account. For the year ended December 31, 2005, $2.9 million was contributed to the reserve and actual expenditures totaled $2.5 million. For the year ended December 31, 2004, $2.8 million was added to the cash reserve and actual expenditures totaled $3.2 million.

19.    Commitments

Provident has office lease commitments that extend through April 2013. Future minimum lease payments for the following five years are: 2006 - $3.8 million; 2007 - $4.1 million; 2008 - $4.2 million; 2009 - $4.1 million; and 2010 - $3.2 million.

In relation to the midstream services and marketing segment, Provident is committed to minimum lease payments under the terms of various rail tank car leases for the following five years: 2006 - US $4.8 million; 2007 - US $3.8 million; 2008 - US $2.8 million; 2009 - US $1.6 million; and 2010 - US $0.6 million.

In relation to the United States oil and natural gas production segment, Provident has surety bonds to provide US $4.9 million of coverage to Occidental Petroleum Corporation related to a purchase of oil and gas producing properties.

In relation to the United States oil and natural gas production segment, Provident leases certain property and equipment under operating leases. Future minimum lease payments for the following five years are as follows: 2006 - US $0.5 million; 2007 - US $0.5 million; 2008 - US $0.5 million; 2009 - US $0.5 million; and 2010 - $0.6 million.

20.    Segmented information

The Trust’s business activities are conducted through three business segments: Canadian oil and natural gas production, United States oil and natural gas production (USOGP) and midstream services and marketing.

Oil and natural gas production in Canada and the United States includes exploitation, development and production of crude oil and natural gas reserves. Midstream services and marketing includes processing, extraction, transportation, loading and storage of natural gas liquids, and marketing of natural gas liquids.

Geographically the Trust operates in Canada and the USA in the oil and gas production business segment. The geographic components have been presented for the oil and natural gas business as well as the midstream services and marketing business that operates in both Canada and the USA.

22

	Year ended December 31, 2005
		Canada Oil and Natural Gas Production			United States Oil and Natural Gas Production			Total Oil and Natural Gas Production			Midstream Services and Marketing (1)			Inter- segment Elimination			Total
Revenue
Gross production revenue		$	466,945		$	154,816		$	621,761		$	-		$	-		$	621,761
Royalties			(95,403	)		(15,019	)		(110,422	)		-			-			(110,422	)
Product sales and service revenue			-			-			-			998,531			(90,420	)		908,111
Realized loss on financial derivative instruments			(48,308	)		(16,323	)		(64,631	)		(2,229	)		-			(66,860	)
			323,234			123,474			446,708			996,302			(90,420	)		1,352,590
Expenses
Cost of goods sold			-			-			-			876,984			(90,420	)		786,564
Production, operating and maintenance			95,278			39,513			134,791			36,402			-			171,193
Transportation			5,702			-			5,702			1,230			-			6,932
Foreign exchange gain and other			(1,815	)		(504	)		(2,319	)		(569	)		-			(2,888	)
General and administrative			18,552			11,490			30,042			11,566			-			41,608
			117,717			50,499			168,216			925,613			(90,420	)		1,003,409
Earnings before interest, taxes, depletion, depreciation, accretion and other non-cash items			205,517			72,975			278,492			70,689			-			349,181
Non-cash revenue
Unrealized gain/(loss) on financial derivative instruments			13,302			(1,910	)		11,392			(1,564	)		-			9,828
Amortization of loss on financial derivative instruments			(2,144	)		-			(2,144	)		-			-			(2,144	)
			11,158			(1,910	)		9,248			(1,564	)		-			7,684
Other expenses
Depletion, depreciation and accretion			155,929			25,553			181,482			11,754			-			193,236
Loss on redemption of convertible debentures			31			10			41			8			-			49
Interest on bank debt			6,833			2,292			9,125			1,750			-			10,875
Interest and accretion on convertible debentures			12,342			4,141			16,483			3,160			-			19,643
Amortization of deferred financing charges			885			297			1,182			227			-			1,409
Unrealized foreign exchange gain			-			-			-			(405	)		-			(405	)
Non-cash unit based compensation			2,640			6,098			8,738			1,015			-			9,753
Internal management charge			(1,695	)		1,695			-			-			-			-
Gain on sale of assets			-			-			-			(5,188	)		-			(5,188	)
Capital taxes			4,780			-			4,780			-			-			4,780
Current and withholding taxes			-			5,628			5,628			-			-			5,628
Future income tax (recovery) expense			(560	)		18,320			17,760			33			-			17,793
			181,185			64,034			245,219			12,354			-			257,573
Non-controlling interest - USOGP			-			1,596			1,596			-			-			1,596
Non-controlling interest - Exchangeables			138			13			151			619			-			770
Net income for the year		$	35,352		$	5,422		$	40,774		$	56,152		$	-		$	96,926
(1) Included in the Midstream Services and Marketing segment is product sales and service revenue of $19.7 million associated with U.S. operations.

23

	Year ended December 31, 2005
	Canada Oil and Natural Gas Production		United States Oil and Natural Gas Production		Total Oil and Natural Gas Production		Midstream Services and Marketing		Inter- segment Elimination		Total
Selected balance sheet items
Capital Assets
Property, plant and equipment net	$	634,732	$	351,073	$	985,805	$	716,884	$	-	$	1,702,689
Intangible assets		-		-		-		215,850		-		215,850
Goodwill		330,944		-		330,944		98,124		-		429,068
Capital Expenditures
Property, plant and equipment net		85,402		52,897		138,299		18,200		-		156,499
Property, plant and equipment through corporate acquisitions		-		99,877		99,877		428,066		-		527,943
Goodwill additions		-		-		-		98,124		-		98,124
Working capital
Accounts receivable		135,220		22,310		157,530		109,716		-		267,246
Petroleum product inventory		-		-		-		110,638		-		110,638
Accounts payable and accrued liabilities		177,798		46,462		224,260		90,463		-		314,723
Long-term debt	$	238,843	$	168,075	$	406,918	$	477,686	$	-	$	884,604

24

	Year ended December 31, 2004 (1)
	Canada Oil and Natural Gas Production			United States Oil and Natural Gas Production			Total Oil and Natural Gas Production			Midstream Services and Marketing			Inter- segment Elimination			Total
Revenue
Gross production revenue	$	405,181		$	44,688		$	449,869		$	-		$	-		$	449,869
Royalties		(85,190	)		(4,009	)		(89,199	)		-			-			(89,199	)
Product sales and service revenue		-			-			-			1,031,019			(190,835	)		840,184
Realized loss on financial derivative instruments		(65,366	)		(425	)		(65,791	)		(3,153	)		-			(68,944	)
		254,625			40,254			294,879			1,027,866			(190,835	)		1,131,910
Expenses
Cost of goods sold		-			-			-			932,476			(190,835	)		741,641
Production, operating and maintenance		90,330			13,173			103,503			37,990			-			141,493
Transportation		5,087			-			5,087			-			-			5,087
Foreign exchange (gain) loss and other		(4	)		(2,239	)		(2,243	)		763			-			(1,480	)
General and administrative		16,439			4,113			20,552			6,552			-			27,104
		111,852			15,047			126,899			977,781			(190,835	)		913,845
Earnings before interest, taxes, depletion, depreciation, accretion and other non-cash items		142,773			25,207			167,980			50,085			-			218,065
Non-cash revenue
Unrealized gain (loss) on non-hedging derivative instruments		3,788			(3,182	)		606			331			-			937
Amortization of loss on non-hedging derivative instruments		(22,990	)		-			(22,990	)		-			-			(22,990	)
		(19,202	)		(3,182	)		(22,384	)		331			-			(22,053	)
Other expenses
Depletion, depreciation and accretion		160,271			7,402			167,673			9,609			-			177,282
Interest on bank debt		7,380			1,252			8,632			3,184			-			11,816
Interest and accretion on convertible debentures		9,812			1,372			11,184			3,989			-			15,173
Amortization of deferred financing charges		947			98			1,045			390			-			1,435
Unrealized foreign exchange gain		-			(744	)		(744	)		-						(744	)
Non-cash unit based compensation		877			822			1,699			120			-			1,819
Capital taxes		5,292			-			5,292			629			-			5,921
Current and withholding taxes		-			1,201			1,201			81			-			1,282
Future income tax recovery		(40,457	)		-			(40,457	)		(120	)		-			(40,577	)
		144,122			11,403			155,525			17,882			-			173,407
Non-controlling interest - USOGP		-			923			923			-			-			923
Non-controlling interest - Exchangeables		(492	)		217			(275	)		732			-			457
Net income (loss) for the year	$	(20,059	)	$	9,482		$	(10,577	)	$	31,802		$	-		$	21,225

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	Year ended December 31, 2004
	Canada Oil and Natural Gas Production		United States Oil and Natural Gas Production		Total Oil and Natural Gas Production		Midstream Services and Marketing		Inter- segment Elimination			Total
Selected balance sheet items
Capital Assets
Property, plant and equipment net	$	763,306	$	254,547	$	1,017,853	$	281,801	$	-		$	1,299,654
Goodwill		330,944		-		330,944		-		-			330,944
Capital Expenditures
Property, plant and equipment net		61,454		12,410		73,864		2,457		-			76,321
Property, plant and equipment through corporate acquisitions		272,259		214,261		486,520		1,300		-			487,820
Goodwill additions		228,501		-		228,501		-		-			228,501
Working capital
Accounts receivable		78,299		11,137		89,436		67,017		(13,311	)		143,142
Petroleum product inventory		-		-		-		17,151		-			17,151
Accounts payable and accrued liabilities		101,668		28,639		130,307		54,416		(13,311	)		171,412
Long-term debt	$	274,683	$	74,464	$	349,147	$	83,059	$	-		$	432,206

⁽¹⁾ Restated note 3

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21.    Reconciliation of Financial Statements to United States

 Generally accepted Accounting Principles

The consolidated financial statements have been prepared in accordance with accounting principles generally accepted in Canada (“Canadian GAAP”). Any differences in accounting principles as they pertain to the accompanying financial statements are not material except as described below. All adjustments are measurement differences. Disclosure items are not noted.

Consolidated Statements of Earnings - U.S. GAAP
For the year ending December 31 (Cdn$ 000s, except per unit numbers)	2005			2004
(Cdn$000s, except per unit numbers)
Net income as reported	$	96,926		$	21,225
Adjustments
Depletion, depreciation and accretion (a)		13,697			5,067
Depletion, depreciation and accretion other (a)		-			(58,065	)
FAS 133 adjustment (b)		2,144			22,990
Non-cash general and administrative (e)		(1	)		415
Future income recovery (taxes) (a) (b) (c)		(5,357	)		9,556
Accretion on convertible debentures (h)		2,849			2,973
Non-controlling interest - Exchangeable shares (j)		770			457
Net Income – U.S. GAAP	$	111,028		$	4,618

Condensed Consolidated Balance Sheet
As at December 31 (Cdn$ 000s)	2005						2004
		Canadian			US. GAAP			Canadian GAAP			US. GAAP
Assets
Deferred derivative loss (b)	$	-		$	-		$	2,144		$	-
Accounts receivable (f)		267,246			267,246			143,142			145,442
Property, plant and equipment (a)		1,702,689			1,646,200			1,299,654			1,229,468
Liabilities and unitholders’ equity
Long-term debt (h)		884,604			902,083			432,206			437,561
Future income taxes (a) (b) (c) (f)		91,595			73,609			70,629			47,286
Non-controlling interest - Exchangeable shares (j)		8,259			-			35,921			-
Units subject to redemption (i) (j)		-			2,236,360			-			1,503,181
Convertible debentures equity component (h)		19,301			-			9,785			-
Unitholders’ contributions (i)		1,971,707			-			1,438,393			-
Contributed surplus (e)		1,675			1,675			2,002			3,020
Cumulative translation adjustment (g)		(41,785	)		-			(28,848	)		-
Accumulated income (loss)		97,288			(837,253	)		362			(485,832	)
Accumulated cash distributions (i)		(643,360	)		-			(412,646	)
Accumulated other comprehensive loss (f) (g)	$	-		$	(42,679	)	$	-		$	(27,442	)

(a)   Under the Canadian cost recovery ceiling test the recoverability of a cost centre is tested by comparing the carrying value of the cost centre to the sum of the undiscounted proved reserve cash flows expected from the cost centre using future price estimates. If the carrying value is not recoverable, the cost centre is written down to its fair value determined by comparing the future cash flows from the proved plus probable reserves discounted at the Trust’s risk free interest rate. Any excess carrying value of the assets on the balance sheet above fair value would be recorded in depletion, depreciation and accretion expense as a permanent impairment. Under U.S. GAAP, companies utilizing the full cost method of accounting for oil and natural gas activities perform a ceiling test on each cost centre using discounted future net revenue from proved oil and natural gas reserves discounted at 10 percent. Prices used in the U.S. GAAP ceiling tests are those in effect at year-end and financing and administrative expenses are excluded from the calculation. The amounts recorded for depletion and

27

depreciation have been adjusted in the periods as a result of differences in write down amounts recorded pursuant to U.S. GAAP compared to Canadian GAAP.

In computing its consolidated net earnings for U.S. GAAP purposes, the Trust recorded additional depletion in 2004 as a result of the application of the ceiling test. These charges were not required under the Canadian GAAP ceiling tests. As a result of the U.S. GAAP ceiling test, there was no charge for ceiling test impairment for 2005.

(b)   At January 1, 2004, the Trust recorded an unrealized loss of $25.1 million in deferred charges on the consolidated balance sheet that is being recognized in income over the term of the previously designated hedged items. For the period ending December 31, 2005, $2.1 million (2004 - $23.0 million) of this deferred charge has been amortized. Under U.S. GAAP the amortization of the deferred charge has already been captured in prior period accumulated losses. There will be no further U.S./Canadian GAAP differences related to the adoption of this standard.

(c)   The Canadian liability method of accounting for income taxes is similar to the United States FAS 109, Accounting for Income Taxes, which requires the recognition of deferred tax assets and liabilities for the expected future tax consequences of events that have been recognized in Provident’s financial statements or tax returns. Pursuant to U.S. GAAP, enacted tax rates are used to calculate future taxes, whereas Canadian GAAP uses substantively enacted rates.

(d)   The consolidated statements of cash flows and operations and accumulated income (loss) are prepared in accordance with Canadian GAAP and conform in all material respects with U.S. GAAP except for the following;

        (i) Canadian GAAP allows for the presentation of operating cash flow before changes in non-cash working capital items in the consolidated statement of cash flows. This total cannot be presented under U.S. GAAP.

        (ii) U.S. GAAP requires disclosure on the consolidated statement of operations when depreciation, depletion and amortization are excluded from cost of goods sold. This disclosure has not been noted on the face of the consolidated statement of operations.

(e)   Provident harmonized its accounting treatment of unit based compensation with U.S. GAAP in 2003 by adopting CICA handbook section 3870, “Stock-based compensation and other stock-based payments.” For U.S. GAAP purposes Provident follows FAS 123, “Accounting for stock-based compensation.” Adoption of CICA handbook section 3870 allows for prospective application whereby options granted during or subsequent to 2003 are fair valued. Under FAS 123, all option grants are fair valued.

(f)   Included in accounts receivable in 2004 is a marketable security that is being held for sale. The Trust follows the cost method of accounting for an investment in a marketable security as established by the CICA. Under this accounting policy, the investment is initially recorded at cost with dividends recorded as income. Under U.S. GAAP, the marketable securities are considered held for sale and recorded on the balance sheet at fair value. The corresponding difference between the cost method and fair value is recorded to other comprehensive loss in the current year and results in a Canadian/U.S. GAAP difference.

(g)   U.S. GAAP requires gains or losses arising from the translation of self-sustaining operations to be included in other comprehensive losses. Canadian GAAP requires these amounts to be recorded in unitholders’ equity.

(h)   Effective December 31, 2004, the Trust retroactively adopted the revised CICA Handbook Section 3860 ("HB 3860"), "Financial Instruments - Presentation and Disclosure" for financial instruments that may be settled at the issuer's option in cash or its own equity. As a result of the implementation of this standard, a U.S./Canadian GAAP difference has arisen. Under U.S. GAAP, the convertible debentures are disclosed as long-term debt at their face value versus Canadian GAAP that requires discounting of the convertible debentures, accretion expense to represent the unwinding of the discounted convertible debentures and a value be assigned within equity to the conversion feature attached to the convertible debentures.

28

(i)   Under U.S. GAAP, a redemption feature of equity instruments exercisable at the option of the holder requires that such equity be excluded from classification as permanent equity and be reported as a liability at the equity’s redemption value. Changes in redemption value in the period are charged to accumulated earnings. Under Canadian GAAP, such equity instruments are considered to be permanent equity and are presented as unitholder’s equity. The Trust’s units and exchangeable shares both have a redemption feature, which qualify them to be considered under this guidance.

In prior years, the Trust believed there were sufficient restrictions on the redemption feature that qualified the trust units and exchangeable shares as permanent equity for U.S. GAAP purposes (note 12). Based on a review conducted in the current year, it was determined that the trust units and exchangeable shares should be accounted for as units subject to redemption in accordance with U.S. GAAP. Accumulated earnings have been reduced by $463.5 million (2004 - $396.9 million) and $2,236.4 million (2004 - $1,503.2 million) has been reclassified to units subject to redemption.

(j)   Under Canadian GAAP, the Trust’s exchangeable shares are classified as non-controlling interest. As these exchangeable shares can be converted into trust units at the option of the holder, the exchangeable shares are classified as units subject to redemption along with the trust units for U.S. GAAP purposes.

29

Recent U.S. Accounting Pronouncements

Accounting for conditional asset retirement obligations

In 2005, FASB issued Financial Interpretation 47 “Accounting for Conditional Asset Retirement Obligations”. This interpretation clarifies that the term conditional asset retirement obligation as used in FAS 143 “Accounting for Asset Retirement Obligations” refers to a legal obligation to perform an asset retirement activity in which the timing and/or method of settlement are conditional on a future event that may or may not be within the control of the entity. The obligation to perform the asset retirement activity is unconditional even though uncertainty exists about the timing and/or method of settlement. Thus, the timing and/or method of settlement may be conditional on a future event. Accordingly, an entity is required to recognize a liability for the fair value of a conditional asset retirement obligation if the fair value of the liability can be reasonably estimated. This interpretation is effective no later than the end of fiscal years ending after December 15, 2005. The adoption of this statement has not had a material impact on the Trust’s consolidated financial statements.

Accounting changes and error corrections

In 2005, FASB issued FAS 154 “Accounting Changes and Error Corrections” which replaces APB Opinion 20. This statement changes the requirements for the accounting and reporting of a change in accounting principle. FAS 154 requires retrospective application of voluntary changes in accounting principles to prior period financial statements, unless it is impracticable to do so. The statement is effective for fiscal years beginning after December 15, 2005. The Trust does not expect the adoption of this statement to have a material impact on its financial statements.

Share-based payment

In 2004, FASB issued revised FAS 123 “Share-Based Payment”. This amended statement eliminates the alternative to use Accounting Principles Board (“APB”) Opinion No. 25’s intrinsic value method of accounting, as was provided in the originally issued Statement 123. As a result, public entities are required to use the grant-date fair value of the award in measuring the cost of employee services received in exchange for an equity award of equity instruments. Compensation cost is not recognized for equity instruments for which employees do not render the requisite service. This amended statement is effective the beginning of the first interim or annual reporting period that begins after June 15, 2005. The Trust does not expect the adoption of this statement to have a material impact on its financial statements.

Exchange of non-monetary assets

In 2004, FASB issued FAS 153 “Exchange of Non-monetary Assets”. This statement is an amendment of APB Opinion No. 29 “Accounting for Non-monetary Transactions”. Based on the guidance in APB Opinion No. 29, exchanges on non-monetary assets are to be measured based on the fair value of the assets exchanged. Furthermore, APB Opinion No. 29 previously allowed for certain exceptions to this fair value principle. FAS 153 eliminates APB Opinion No. 29’s exception to fair value for non-monetary exchanges of similar productive assets and replaces this with a general exception for exchange of non-monetary assets that do not have commercial substance. For purposes of this statement, a non-monetary exchange is defined as having commercial substance when the future cash flows of an entity are expected to change significantly as a result of the exchange. The provisions of this statement are effective for non-monetary asset exchanges that occur in fiscal periods beginning after June 15, 2005 and are to be applied prospectively. Earlier application is permitted for non-monetary asset exchanges that occur in fiscal periods beginning after the issue date of this statement. The Trust does not expect the adoption of this statement to have a material impact on its financial statements.

30

ADDITIONAL DISCLOSURE

Certifications and Disclosure Regarding Controls and Procedures.

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

(b) Disclosure Controls and Procedures. As of the end of the registrant’s fiscal year ended December 31, 2005, an evaluation of the effectiveness of the registrant’s “disclosure controls and procedures” (as such term is defined in Rules 13a-15(e) and 15d-15(e) of the Securities Exchange Act of 1934, as amended (the “Exchange Act”)) was carried out by the management of Provident Energy Ltd., the administrator of the registrant, with the participation of the Chief Executive Officer (“CEO”) and Chief Financial Officer (“CFO”) of Provident Energy Ltd., who also perform such functions for the registrant. Based upon that evaluation, the CEO and CFO have concluded that as of the end of that fiscal year, the registrant’s disclosure controls and procedures are effective to ensure that information required to be disclosed by the registrant in reports that it files or submits under the Exchange Act is (i) recorded, processed, summarized and reported within the time periods specified in Securities and Exchange Commission rules and forms and (ii) accumulated and communicated to the registrant’s management, including its principal executive officer and principal financial officer, to allow timely decisions regarding required disclosure.

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

(c) Changes in Internal Control Over Financial Reporting. During the fiscal year ended December 31, 2005, there were no changes in the registrant’s internal control over financial reporting that have materially affected, or are reasonably likely to materially affect, the registrant’s internal control over financial reporting.

Notices Pursuant to Regulation BTR.

None.

Audit Committee Financial Expert.

The registrant’s board of directors has determined that Mike H. Shaikh, a member of the registrant’s audit committee, qualifies as an “audit committee financial expert” (as such term is defined in Form 40-F). Mr. Shaikh is “independent” as that term in defined in the rules of the New York Stock Exchange.

Code of Business Conduct.

The registrant has adopted a “code of business conduct” (which qualifies as a Code of Ethics that meets the requirements as defined in Form 40-F) that applies to its principal executive officer, principal financial officer, principal accounting officer or controller, and persons performing similar functions.

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

In connection with the registrant’s listing on the New York Stock Exchange, the Code of Business Conduct was amended in March 2006 to reflect the New York Stock Exchange’s guidelines for codes of ethics. The amended Code of Business Conduct is filed as Exhibit 99.9 to this Annual Report on Form 40-F. Since the adoption of the Code of Business Conduct, there have not been any waivers, including implicit waivers, from any provision of the Code of Business Conduct.

Principal Accountant Fees and Services.

The required disclosure in included under the heading Audit Committee Information in the Annual Information Form included as part of this form.

The following table sets forth information about the fees billed to the Trust for professional services provided by PricewaterhouseCoopers LLP during fiscal 2005 and 2004:

(CDN$)	2005		2004
Audit Fees	$	929,000	$	868,000
Audit-Related Fees		30,000		90,750
Tax Fees		776,300		375,000
All Other Fees		-		-
Total	$	1,735,300	$	1,333,750

Fees. Audit fees consist of fees for the audit of the registrant’s annual financial statements or services that are normally provided in connection with statutory and regulatory filings or engagements.

Audit-Related Fees. Audit-related fees consist of fees for assurance and related services that are reasonably related to the performance of the audit or review of the registrant’s financial statements and are not reported as Audit Fees. During fiscal 2005 and 2004, the services provided in this category included due diligence reviews in connection with acquisitions, research of accounting and audit-related issues and the completion of audits required by contracts to which the registrant is a party.

Tax Fees. Tax fees consist of fees for tax compliance services, tax advice and tax planning. During fiscal 2005 and 2004, the services provided in this category included assistance and advice in relation to the preparation of corporate income tax returns.

All Other Fees. None.

Pre-Approval Policies and Procedures.

(a)   All proposed services or the fees payable in connection with such services that have not already been pre-approved must be pre-approved by either the audit committee or pursuant to Delegated Authority (as defined below). The audit committee has delegated authority to the chairman of the audit committee to pre-approve the provision of permitted services by PricewaterhouseCoopers LLP and not otherwise pre-approved by the full audit committee, including the fees and terms of the proposed services (“Delegated Authority”). All pre-approvals granted pursuant to Delegated Authority must be presented by the chairman to the full audit committee at its next meeting. The fees payable in connection with any particular service to be provided by PricewaterhouseCoopers LLP that has been pre-approved pursuant to Delegated Authority may not exceed Cdn.$50,000. Amounts exceeding Cdn.$50,000 must be pre-approved by the full audit committee. Prohibited services may not be pre-approved by the audit committee or pursuant to Delegated Authority.

 (b)   Of the fees reported in this Annual Report on Form 40-F under the heading “Principal Accountant Fees and Services”, nil of the fees billed by PricewaterhouseCoopers LLP were approved by the audit committee of the registrant pursuant to the de minimus exception provided by Section (c)(7)(i)(C) of Rule 2-01 of Regulation S-X.

Off-Balance Sheet Arrangements.

The Trust does not have any off-balance sheet arrangements.

Tabular Disclosure of Contractual Obligations.

(CDN$ millions)		Payment due by period
Contractual Obligations	Total	Less than 1 Year	2 to 3 Years	3 to 5 Years	More than 5 Years
Long-Term Debt Obligations	884.6	-	618.2	32.4	234.0
Capital (Finance) Lease Obligations	-	-	-	-	-
Operating Lease Obligations	50.1	9.9	17.3	11.2	11.7
Purchase Obligations	-	-	-	-	-
Other Long-Term Liabilities Reflected on the Registrant’s Balance Sheet under Canadian GAAP	41.1	-	-	-	41.1
Total	975.8	9.9	635.5	43.6	286.8

Identification of the Audit Committee.

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

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

Presiding Director at Meetings of Non-Management Directors

The registrant schedules regular executive sessions in which the registrant's "non-management directors" (as that term is defined in the rules of the New York Stock Exchange) meet without management participation. Mr. John Zaozirny serves as the presiding director (the "Presiding Director") at such sessions. Each of the registrant's non-management directors is "unrelated" as such term is used in the rules of the Toronto Stock Exchange. The Provident Board of Directors is responsible for determining whether or not each director is independent. In making this determination, the Board has adopted the definition of "independence" as set out in Section 1.4 of Multilateral Instrument 52-110 Audit Committees ("MI-51-110"). In applying this definition, the Board considers all relationships of the directors with Provident, including business, family and other relationships. Provident's Board of Directors also determines whether each member of Provident's Audit Committee is independent pursuant to Sections 1.4 and 1.5 of MI 52-110 and Rule 10A-3 of the Securities Exchange Act of 1934. Provident's Board of Directors has not adopted the director independence standards contained in Section 303A.02 of the NYSE's Listed Company Manual.

Communication with Non-Management Directors

Shareholders may send communications to the registrant's non-management directors by writing to the Presiding Director, c/o Lynn M. Rannelli, Assistant Corporate Secretary, Provident Energy Ltd., 800, 112-4^th Avenue S.W., Calgary, Alberta, Canada T2P 0H3. Communications will be referred to the Presiding Director for appropriate action. The status of all outstanding concerns addressed to the Presiding Director will be reported to the board of directors as appropriate.

Corporate Governance Guidelines

According to Section 303A.09 of the NYSE Listed Company Manual, a listed company must adopt and disclose a set of corporate governance guidelines with respect to specified topics. Such guidelines are required to be posted on the listed company's website. The registrant operates under corporate governance principles that are consistent with the requirements of Section 303A.09 of the NYSE Listed Company Manual, many of which are described under the heading "Statement of Corporate Governance Practices" in the registrant's Information Circular in connection with its 2006 Annual Meeting. However, the registrant has not codified its corporate governance principles into formal guidelines in order to post them on its website.

Board Committee Mandates

The Mandates of the registrant's audit committee, human resources and compensation committee, and nominating and corporate governance committee are each available for viewing on the registrant's website at www.providentenergy.com, and are available in print to any unitholder who requests them. Requests for copies of these documents should be made by contacting: Lynn M. Rannelli, Assistant Corporate Secretary, Provident Energy Ltd., 800, 112-4^th Avenue S.W., Calgary, Alberta, Canada T2P 0H3.

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

UNDERTAKING AND CONSENT TO SERVICE OF PROCESS

A.Undertaking.

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

B. Consent to Service of Process.

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

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

SIGNATURES

Pursuant to the requirements of the Exchange Act, the registrant certifies that it meets all of the requirements for filing on Form 40-F and has duly caused this annual report to be signed on its behalf by the undersigned, thereunto duly authorized, on March 28, 2005.

PROVIDENT ENERGY TRUST

By: Provident Energy Ltd.

By: /s/Thomas W. Buchanan

Name: Thomas W. Buchanan

Title: Chief Executive Officer

EXHIBIT INDEX

Exhibit	Description
99.1	Certification of Chief Executive Officer pursuant to Rule 13a-14(a) or 15d-14 of the Securities Exchange Act of 1934
99.2	Certification of Chief Financial Officer pursuant to Rule 13a-14(a) or 15d-14 of the Securities Exchange Act of 1934
99.3	Section 1350 Certification of Chief Executive Officer
99.4	Section 1350 Certification of Chief Financial Officer
99.5	Consent of PricewaterhouseCoopers LLP (Calgary)
99.6	Consent of McDaniel & Associates Consultants Ltd.
99.7	Consent of Netherland Sewell & Associates Inc.
99.8	Consent of Cawley Gillespie & Associates Inc.
99.9	Amended Code of Business Conduct