d40f.htm

RENEWAL ANNUAL INFORMATION FORM

For the year ended December 31, 2007

March 27, 2008

TABLE OF CONTENTS

Page		Page

GLOSSARY OF TERMS	1	RISK MANAGEMENT	27
ABBREVIATIONS, TERMS AND CONVERSIONS	4	General	27
PRESENTATION OF OIL AND GAS RESERVES AND PRODUCTION INFORMATION	5	Risk Management	28
NON-GAAP MEASURES	5	OIL AND NATURAL GAS OPERATIONS	30
NOTE REGARDING FORWARD LOOKING STATEMENTS	6	NATURAL GAS MIDSTREAM, NGL PROCESSING AND MARKETING OPERATIONS	30
INCORPORATION AND STRUCTURE	8	General
The Trust	8	NGL Extraction	31
Provident	8	NGL Fractionation	31
Provident Holdings Trust	9	NGL Transportation	31
Provident Acquisitions L.P	9	NGL Storage	32
Provident Midstream L.P	9	NGL Marketing	32
Provident Acquisitions Inc	9	Commercial Arrangements	32
Provident Midstream Inc	9	Midstream services and marketing assets	33
Provident Energy Resources Inc	10	MARKET FOR SECURITIES	35
Pro Holding Company	10	RECORD OF CASH DISTRIBUTIONS	37
BreitBurn Energy Company L.P	10	PREMIUM DISTRIBUTION, DISTRIBUTION REINVESTMENT AND OPTIONAL UNIT PURCHASE PLAN	38
BreitBurn Energy Partners L.P	10	DIRECTORS AND OFFICERS	39
INTERCORPORATE RELATIONSHIPS	10	AUDIT COMMITTEE INFORMATION	44
INFORMATION CONCERNING THE TRUST, PROVIDENT AND CERTAIN SUBSIDIARIES	11	INFORMATION CONCERNING THE OIL AND GAS INDUSTRY	47
Provident Energy Trust	11	RISK FACTORS	50
Provident Energy Ltd	20	Oil and Gas Production Risk Factors	50
Provident Holdings Trust, Provident Acquisitions L.P., Provident Marketing L.P. and Provident Midstream L.P	21	Natural Gas Midstream, NGL Processing and Marketing Business Risk Factors	54
Provident Energy Resources Inc	22	General Risk Factors	57
Provident Acquisitions Inc	22	INTERESTS OF MANAGEMENT AND OTHERS IN MATERIAL TRANSACTIONS	60
Provident Midstream Inc	22	TRANSFER AGENT AND REGISTRAR	60
Pro Holding Company	22	INTERESTS OF EXPERTS	60
BreitBurn Energy Company L.P	22	MATERIAL CONTRACTS	60
BreitBurn Energy Partners L.P	23	DOCUMENTS INCORPORATED BY REFERENCE	60
GENERAL DEVELOPMENT OF THE BUSINESS OF THE TRUST AND PROVIDENT	23	PRINCIPAL HOLDERS OF TRUST UNITS	61
		ADDITIONAL INFORMATION	61

SCHEDULE A -

AUDIT COMMITTEE INFORMATION

GLOSSARY OF TERMS

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

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

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

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

"AJM" means AJM Petroleum Consultants, independent petroleum engineers;

"AMEX" means the American Stock Exchange;

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

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

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

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

"BreitBurn MLP" means BreitBurn Energy Partners L.P., a publicly traded Delaware limited partnership;

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

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

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

"Holdings Trust" means Provident Holdings Trust;

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

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

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

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

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

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

"Nautilus" means Nautilus Resources LLC;

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

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

"NYSE" means the New York Stock Exchange;

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

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

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

"PAI" means Provident Acquisitions Inc.;

"PERI" means Provident Energy Resources Inc.;

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

"PMI" means Provident Midstream Inc.;

"PHC" means Pro Holding Company;

"Provident" means Provident Energy Ltd.;

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

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

"Schlumberger" means Data & Consulting Services Division of Schlumberger Technology Corporation;

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

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

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

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

(a)	a body corporate which is controlled by (i) that other, or (ii) that other and one or more bodies corporate, each of which is controlled by that other, or (iii) two or more 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 Percent Debentures" means the 6.5 percent convertible unsecured subordinated debentures of the Trust issued on November 15, 2005;

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

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

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

"Trust Fund", at any time, shall mean such of the following monies, properties and assets that are at such time held by the Trustee for the purposes of the Trust under the Trust Indenture: (a) the initial $100 used to settle the Trust; (b) all funds realized from the issuance of Trust Units; (c) any Permitted Investments in

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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;

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

"TSX" means the Toronto Stock Exchange;

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

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

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

ABBREVIATIONS, TERMS AND CONVERSIONS

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

Oil and Natural Gas Liquids		Natural Gas

bbls	barrels	mcf	thousand cubic feet
boed or boe/d	barrels of oil equivalent per day	bcf/d	billion cubic feet per day
bpd or bbl/d	barrels of oil per day	m3	cubic metres
mmbbls	million barrels	mmbtu	million British Thermal Units
NGLs	natural gas liquids	gj	gigajoule
STB	stock tank barrel of oil

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.
WTI	means West Texas Intermediate.
API	means the measure of the density or gravity of liquid petroleum products derived from a specific gravity.

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

NON-GAAP MEASURES

In this Renewal Annual Information Form, the Trust uses the terms "cash flow", "adjusted cash flow" and "funds flow from operations" to refer to the amount of cash available for distribution to Unitholders and as indicators of financial performance. "Cash flow", "adjusted cash flow" and "funds flow from operations" are not measures recognized by Canadian generally accepted accounting principles ("GAAP") and do not have standardized meanings prescribed by GAAP. Therefore, "cash flow", "adjusted cash flow" and "funds flow from operations" of the Trust may not be comparable to similar measures presented by other issuers, and investors are cautioned that "cash flow", "adjusted cash flow" and "funds flow from operations" should not be construed as alternatives to net earnings, cash flow from operating activities or other measures of financial performance calculated in accordance with GAAP. All references to "cash flow", "adjusted cash flow" and "funds flow from operations" are based on cash provided by operating activities before changes in non-cash working capital related to operating activities and site restoration expenditures, as presented in the consolidated financial statements of the Trust. The actual amount of cash that is distributed cannot be assured and future distributions may vary. Management also uses EBITDA to analyze the operating performance of the Midstream business unit. EBITDA as presented does not have any standardized meaning prescribed by Canadian GAAP and therefore it may not be comparable with the calculation of similar measures for other entities. EBITDA as presented is not intended to represent operating cash flow or operating profits for the period nor should it be viewed as an alternative to cash flow from operating activities, net earnings or other measures of financial performance calculated in accordance with Canadian GAAP. All references to EBITDA throughout this report are based on earnings before interest, taxes, depletion, depreciation, accretion, and other non-cash items ("EBITDA"). The Trust uses such terms as an indicator of financial performance because such terms are commonly utilized by investors to evaluate royalty trusts and income funds in the energy sector. The Trust believes that such terms are useful supplemental measures as they provide investors with information of what cash is available for distribution from the Trust to Unitholders in such periods.

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NOTE REGARDING FORWARD LOOKING STATEMENTS

This Renewal Annual Information Form and the documents incorporated by reference herein contain forward-looking information or forward-looking statements under applicable securities legislation. These statements relate to future events or the Trust's future performance. Such forward-looking statements or information are provided for the purpose of providing information about management's current expectations and plans relating to the future. Readers are cautioned that reliance on such information may not be appropriate for other purposes, such as making investment decisions. All statements other than statements of historical fact are forward-looking statements. In some cases, forward-looking statements can be identified by terminology such as "may", "will", "should", "expect", "plan", "anticipate", "believe", "estimate", "predict", "potential", "continue", or the negative of these terms or other comparable terminology. Statements relating to "reserves" or "resources" are deemed to be forward-looking statements, as they involve the implied assessment, based on certain estimates and assumptions, that the resources and reserves described can be profitably produced in the future. Forward looking statements or information in this Renewal Annual Information Form include, but are not limited to, business strategy and objectives, reserve quantities and the discounted present value of future net cash flows from such reserves, net revenue, future production levels, capital expenditures, exploration plans, development plans, acquisition and disposition plans and the timing thereof, operating and other costs, royalty rates, budgeted levels of cash distributions and the performance associated with Provident's natural gas midstream, NGL processing and marketing business. Forward-looking statements or information are based on current expectations, estimates and projections that involve a number of risks and uncertainties which could cause actual events or results to differ materially from those anticipated by the Trust and described in the forward-looking statements or information. In addition, this Renewal Annual Information Form and the documents incorporated by reference herein may contain forward-looking statements attributed to third party industry sources. Undue reliance should not be placed on forward-looking statements or information, as there can be no assurance that the plans, intentions or expectations upon which they are based will occur. By its nature, forward-looking information involves numerous assumptions, known and unknown risks and uncertainties, both general and specific, that contribute to the possibility that the predictions, forecasts, projections and other forward-looking statements will not occur. Forward-looking statements in this Renewal Annual Information Form and the documents incorporated by reference herein include, but are not limited to, statements with respect to:

the Trust's ability to benefit from the combination of growth opportunities and the ability

to grow through the capital markets;

the Trust's acquisition strategy, the criteria to be considered in connection therewith and

the benefits to be derived therefrom;

sustainability and growth of production and reserves through prudent management and

acquisitions;

the emergence of accretive growth opportunities;

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

the impact of Canadian governmental regulation on the Trust;

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

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

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

hedging;

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

the sale, farming out or development using third party resources to exploit or produce

certain exploration properties;

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

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

currency, exchange and interest rates;

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the performance characteristics of Provident's natural gas midstream, NGL processing

and marketing business;

the growth opportunities associated with the natural gas midstream, NGL processing and

marketing business; and

the nature of contractual arrangements with third parties in respect of Provident's natural

gas midstream, NGL processing and marketing business.

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

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

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

uncertainties associated with estimating reserves;

royalties payable in respect of oil and gas production;

interest payable on notes issued in connection with acquisitions;

income tax legislation relating to income trusts, including the effect of new legislation

taxing trust income;

governmental regulation in North America of the oil and gas industry, including income

tax and environmental regulation;

fluctuation in foreign exchange or interest rates;

stock market volatility and market valuations;

the impact of environmental events;

the need to obtain required approvals from regulatory authorities;

	·	unanticipated operating events which can reduce production or cause production to be shut-in or delayed;
	·	failure to realize the anticipated benefits of acquisitions;
	·	competition for, among other things, capital reserves, undeveloped lands and skilled personnel;

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

required;

risks associated with foreign ownership;

third party performance of obligations under contractual arrangements; and

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

Form.

Readers are cautioned that the foregoing list is not exhaustive of all possible risks and uncertainties. With respect to forwarding looking statements and forward looking information contained in this Renewal Annual Information Form, the Trust has made assumptions regarding, among other things:

future natural gas and crude oil prices;

the ability of the Trust to obtain qualified staff and equipment in a timely and cost-efficient manner to meet demand;

the regulatory framework regarding royalties, taxes and environmental matters in which the Trust conducts its business;

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the impact of increasing competition; and

the Trust's ability to obtain financing on acceptable terms.

the general stability of the economic and political environment in which the Trust operates;

the timely receipt of any required regulatory approvals;

the ability of the operator of the projects which the Trust has an interest in to operate the field in a safe, efficient and effective manner;

field production rates and decline rates;

the ability to replace and expand oil and natural gas reserves through acquisition, development of exploration;

the timing and costs of pipeline, storage and facility construction and expansion and the ability of the Trust to secure adequate product transportation;

currency, exchange and interest rates; and

the ability of the Trust to successfully market its oil and natural gas products.

Readers are cautioned that the foregoing list is not exhaustive of all factors and assumptions which have been used. The forward-looking statements or information contained or incorporated by reference in this Renewal Annual Information Form are made as of the date hereof and the Trust undertakes no obligation to update publicly or revise any forward-looking statements or information, whether as a result of new information, future events or otherwise unless required by applicable securities laws. The forward looking statements or information contained or incorporated by reference in this Renewal Annual Information Form are expressly qualified by this cautionary statement.

INCORPORATION AND STRUCTURE

The Trust

Provident Energy Trust is an open-end unincorporated investment trust governed by the laws of the Province of Alberta and created pursuant to the Trust Indenture. The head and principal offices of the Trust are located at 2100, 250 - 2nd Street S.W., Calgary, Alberta T2P 0C1. The registered office of the Trust is located at 3700, 400 - 3rd Avenue S.W., Calgary, Alberta T2P 4H2.

Provident

Provident Energy Ltd. is a corporation the common shares of which are wholly-owned by the Trust. Provident was incorporated under the ABCA on January 19, 2001 and was amalgamated with Founders pursuant to a plan of arrangement involving the Trust, Provident and Founders effective March 6, 2001. Provident subsequently amalgamated with Maxx Petroleum Ltd. ("Maxx") effective May 25, 2001 pursuant to a plan of arrangement involving the Trust, Provident and Maxx. Provident was also amalgamated with Richland Petroleum Corporation ("Richland") effective January 16, 2002 pursuant to a plan of arrangement involving the Trust, Provident and Richland. Provident was amalgamated with Provident Management Corporation pursuant to a management internalization transaction involving the Trust, Provident, Provident Management Corporation and its shareholders effective January 17, 2003. Provident was also amalgamated with Olympia Energy Inc. and Viracocha Energy Inc. on June 1, 2004 pursuant to plans of arrangement involving the Trust, Provident, Viracocha Energy Inc. and Olympia Energy Inc. The head and principal offices of Provident are located at 2100, 250 - 2nd Street S.W., Calgary, Alberta T2P 0C1. The registered office of Provident is located at 3700, 400 - 3rd Avenue S.W., Calgary, Alberta T2P 4H2.

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Provident Holdings Trust

Provident Holdings Trust is an open-end unincorporated commercial trust governed by the laws of the Province of Alberta. Holdings Trust was formed pursuant to a trust indenture dated April 25, 2002 and is wholly-owned by the Trust. Holdings Trust currently holds a 99 percent limited partnership interest in the limited partnerships, Provident Acquisitions L.P. and Provident Marketing L.P. and an interest in Provident Midstream L.P. The head and principal offices of Holdings Trust are located at 2100, 250 - 2nd Street S.W., Calgary, Alberta T2P 0C1. The registered office of Holdings Trust is located at 3700, 400 – 3rd Avenue S.W., Calgary, Alberta T2P 4H2.

Provident Acquisitions L.P.

Provident Acquisitions L.P. is a limited partnership registered in the Province of Alberta. Provident Acquisitions L.P. was formed pursuant to a limited partnership agreement dated April 19, 2002. The general partner of Provident Acquisitions L.P. is Provident which holds a 1 percent interest in the partnership. Holdings Trust is the limited partner of Provident Acquisitions L.P. with a 99 percent interest in the partnership. The head and principal offices of Provident Acquisitions L.P. are located at 2100, 250 - 2nd Street S.W., Calgary, Alberta T2P 0C1. The registered office of Provident Acquisitions L.P. is located at 3700, 400 - 3rd Avenue S.W., Calgary, Alberta T2P 4H2.

Provident Midstream L.P.

Provident Midstream L.P. is a limited partnership registered in the Province of Alberta. Provident Midstream L.P. was formed pursuant to a limited partnership agreement dated December 8, 2005. Provident Midstream L.P. directly and indirectly holds the Canadian partnership interests acquired pursuant to the Midstream NGL Acquisition. The general partner of Provident Midstream L.P. is Provident GP Inc. which holds a 1 percent interest in the partnership. Holdings Trust and PMI are the limited partners of Provident Midstream L.P. with a 99 percent total interest in the partnership. Provident Midstream L.P. also holds a 98.5 percent partnership interest in Empress NGL Partnership, a general partnership formed under the laws of Alberta, which in turn holds a 99 percent partnership interest in Kinetic Resources LPG, a general partnership formed under the laws of Alberta. The head and principal offices of Provident Midstream L.P. are located at 2100, 250 - 2nd Street S.W., Calgary, Alberta T2P 0C1. The registered office of Provident Midstream L.P. is located at 3700, 400 - 3rd Avenue S.W., Calgary, Alberta T2P 4H2.

Provident Acquisitions Inc.

Provident Acquisitions Inc. is a corporation wholly-owned by Provident. PAI was incorporated under the ABCA on August 19, 2002. The head and principal offices of PAI are located at 2100, 250 - 2nd Street S.W., Calgary, Alberta T2P 0C1. The registered office of PAI is located at 3700, 400 - 3rd Avenue S.W., Calgary, Alberta T2P 4H2.

Provident Midstream Inc.

Provident Midstream Inc. is a corporation wholly-owned by Provident and Pro Holding Company. PMI was incorporated under the ABCA on June 6, 2005. PMI holds Provident's Redwater Midstream NGL asset and also holds an interest in Provident Midstream L.P. The head and principal offices of PMI are located at 2100, 250 - 2nd Street S.W., Calgary, Alberta T2P 0C1. The registered office of PMI is located at 3700, 400 - 3rd Avenue S.W., Calgary, Alberta T2P 4H3.

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Provident Energy Resources Inc.

Provident Energy Resources Inc. is a corporation wholly-owned by Provident. PERI was incorporated under the ABCA on May 9, 2007 PERI amalgamated with Capitol Energy Resources Ltd. on June 21, 2007 and amalgamated with Triwest Energy Inc. on December 4, 2007. The head and principal offices of PERI are located at 2100, 250 - 2nd Street S.W., Calgary, Alberta T2P 0C1. The registered office of PERI is located at 3700, 400 - 3rd Avenue S.W., Calgary, Alberta T2P 4H2.

Pro Holding Company

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

BreitBurn Energy Company L.P.

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

BreitBurn Energy Partners L.P.

BreitBurn Energy Partners L.P. is a publicly traded Delaware limited partnership formed on March 23, 2006. BreitBurn MLP is managed by BreitBurn GP LLC, which has a board of directors comprised of 3 directors or officers of Provident, as well as 4 independent directors. The Trust, through Pro Holding Company, Pro LP Corp. and Pro GP Corp., currently holds approximately 22 percent of the outstanding partnership interests in BreitBurn MLP. The head and principal offices of BreitBurn MLP are located at 515 S. Flower Street, Suite 4800, Los Angeles, California. The registered office of BreitBurn MLP is 2711 Centerville Road, Suite 400, Wilmington, Delaware.

INTERCORPORATE RELATIONSHIPS

The following diagram of the Trust, Provident and the Trust's material subsidiaries describes the flow of cash from the oil and gas properties and the natural gas midstream, NGL processing and marketing business to the Trust and from the Trust to the Unitholders.

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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.

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Cash Distributions

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

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

Trust Units

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

8.75 Percent Debentures

In September 2003, the Trust issued $75.0 million aggregate principal amount of convertible unsecured subordinated debentures. The 8.75 Percent Debentures mature on December 31, 2008 and bear interest at a rate of 8.75 percent per annum, payable semi-annually in arrears on June 30 and December 31 in each year. The 8.75 Percent Debentures are convertible at the option of the holder into Trust Units at any time prior to the earlier of December 31, 2008 and the business day immediately preceding any date specified by the Trust for redemption at a conversion price of $11.05 per Trust Unit, subject to adjustment in certain circumstances. After January 1, 2007 and prior to maturity, the Trust may redeem the 8.75 Percent Debentures in whole or in part from time to time at a price of $1,050 per 8.75 Percent Debenture from January 1, 2007 until January 1, 2008 and at a price of $1,025 per 8.75 Percent Debenture thereafter until maturity, in each case plus accrued and unpaid interest. On redemption or maturity of the 8.75 Percent Debentures, the Trust may, subject to regulatory approval, elect to satisfy the redemption price or principal amount by issuing Trust Units to the 8.75 Percent Debenture holder. As of March 19, 2008, there was $19.9 million aggregate principal amount of 8.75 Percent Debentures outstanding.

8 Percent Debentures

In July 2004, the Trust issued 50.0 million aggregate principal amount of convertible unsecured subordinated debentures. The 8 Percent Debentures mature on July 31, 2009 and bear interest at a rate of 8 percent per annum, payable semi-annually in arrears on July 31 and January 31 in each year.

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The 8 Percent Debentures are convertible at the option of the holder into Trust Units at any time prior to the earlier of July 31, 2009 and the business day immediately preceding any date specified by the Trust for redemption at a conversion price of $12.00 per Trust Unit, subject to adjustment in certain circumstances. After July 31, 2007 and prior to maturity, the Trust may redeem the 8 Percent Debentures in whole or in part from time to time at a price of $1,050 per 8 Percent Debenture from July 31, 2007 until July 31, 2008 and at a price of $1,025 per 8 Percent Debenture thereafter until maturity, in each case plus accrued and unpaid interest. On redemption or maturity of the 8 Percent Debentures, the Trust may, subject to regulatory approval, elect to satisfy the redemption price or principal amount by issuing Trust Units to the 8 Percent Debenture holder. As of March 19, 2008, there was $25.1 million aggregate principal amount of 8 Percent Debentures outstanding.

Initial 6.5 Percent Debentures

In March 2005, the Trust issued $100.0 million aggregate principal amount of convertible unsecured subordinated debentures. The Initial 6.5 Percent Debentures mature on August 31, 2012 and bear interest at a rate of 6.5 percent per annum, payable semi-annually in arrears on August 31 and February 28 in each year. The Initial 6.5 Percent Debentures are convertible at the option of the holder into Trust Units at any time prior to the earlier of August 31, 2012 and the business day immediately preceding any date specified by the Trust for redemption at a conversion price of $13.75 per Trust Unit, subject to adjustment in certain circumstances. After August 31, 2008 and prior to maturity, the Trust may redeem the Initial 6.5 Percent Debentures in whole or in part from time to time at a price of $1,050 per Initial 6.5 Percent Debenture from August 31, 2008 until August 31, 2009, at a price of $1,025 per Initial 6.5 Percent Debenture after August 31, 2009 and on or before August 31, 2010 and after August 31, 2010 and prior to maturity at a price of $1,000 per Initial 6.5 Percent Debenture, in each case plus accrued and unpaid interest. On redemption or maturity of the Initial 6.5 Percent Debentures, the Trust may, subject to regulatory approval, elect to satisfy the redemption price or principal amount by issuing Trust Units to the Initial 6.5 Percent Debenture holder. As of March 19, 2008, there was $99.0 million aggregate principal amount of Initial 6.5 Percent Debentures outstanding.

Supplemental 6.5 Percent Debentures

In November 2005, the Trust issued $150.0 million aggregate principal amount of convertible unsecured subordinated debentures. The Supplemental 6.5 Percent Debentures mature on April 30, 2011 and bear interest at a rate of 6.5 percent per annum, payable semi-annually in arrears on April 30 and October 31 in each year, commencing April 30, 2006. The Supplemental 6.5 Percent Debentures are convertible at the option of the holder into Trust Units at any time prior to the earlier of April 30, 2011 and the business day immediately preceding any date specified by the Trust for redemption at a conversion price of $14.75 per Trust Unit, subject to adjustment in certain circumstances. After October 31, 2008 and prior to maturity, the Trust may redeem the Supplemental 6.5 Percent Debentures in whole or in part from time to time at a price of $1,050 per 6.5 Percent Debenture from October 31, 2008 until October 31, 2009, at a price of $1,025 per Supplemental 6.5 Percent Debenture after October 31, 2009 and on or before October 31, 2011, in each case plus accrued and unpaid interest. On redemption or maturity of the Supplemental 6.5 Percent Debentures, the Trust may, subject to regulatory approval, elect to satisfy the redemption price or principal amount by issuing Trust Units to the Supplemental 6.5 Percent Debenture holder. As of March 19, 2008, there was $150.0 million aggregate principal amount of Supplemental 6.5 Percent Debentures outstanding.

Debt Financing

The trust has entered into a credit agreement (the "Canadian Credit Facility") dated as of May 4, 2007, as amended, among the Trust, National Bank of Canada, as administrative agent, and a syndicate of Canadian chartered banks and other Canadian and U.S. financial institutions (the "Lenders"). Pursuant to the Canadian Credit Facility, the Lenders have agreed to provide the Trust with a revolving credit facility in the principal amount of $1.105 billion (or the equivalent in U.S. dollars) and an operating credit facility in the principal amount of $20 million (or the equivalent in U.S. dollars) for the general corporate purposes of the Trust.

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The Canadian Credit Facility bears interest in accordance with a pricing grid based on Provident's debt to EBITDA multiple calculated using the most recent quarter's EBITDA on an annualized basis. Based on Provident's EBITDA for the year ended December 31, 2007, the interest rate pursuant to the pricing grid in Canadian bankers acceptance plus 0.85 percent. The Canadian Credit Facility is secured by a first fixed and floating charge debenture, a general assignment of book debts, a negative pledge and an undertaking to provide, if determined necessary by the Lenders, first charges over major petroleum and natural gas reserves of Provident.

Provident may draw on the facility by way of Canadian prime rate loans, U.S. base rate loans, banker’s acceptances, letters of credit or LIBOR loans. At December 31, 2007, $925.3 million was drawn on the Canadian Credit Facility.

The Canadian Credit Facility has a revolving three year term expiring on May 30, 2010. Provident can extend the revolving period by an additional year, no earlier than 90 days and no later than 30 days prior to the end of the first year of the applicable three year revolving period. If the Lenders do not extend the revolving period, or Provident chooses not to extend, the credit facility will be terminated and the loan balance will become due and payable in full on the maturity date.

In accordance with the Canadian Credit Facility, the Trust must maintain certain financial covenants so long as any indebtedness is outstanding under the facility and will not assume or create any mortgage, charge or encumbrance on the assets of the Trust or certain subsidiaries other than permitted encumbrances. In addition, the facility contains other standard covenants restricting the Trust's ability to incur indebtedness, dispose of assets, enter into hedging arrangements or amend, supplement, cancel or terminate any material term of the Trust Indenture (except for any changes that are not adverse to the Lenders). The Canadian Credit Facility also prohibits distributions to the Unitholders: (i) if they are out of the ordinary course of business; (ii) during the period commencing after a borrowing base shortfall has occurred (as defined in the facility) and ending when such shortfall has been eliminated; (iii) during the period commencing after a default has occurred and ending when such default has been cured; (iv) after an event of default has occurred; (v) after the maturity date; (vi) if they would cause a default or event of default or would impair the ability of the Trust or its subsidiaries to fulfill its obligations under the Canadian Credit Facility or the security provided in respect thereof; and (vii) the aggregate amount of such distributions and payments during the preceding four fiscal quarters exceeds cumulative available cash flow (as defined in the facility).

The events of default under the Canadian Credit Facility include a default in payment of any principal or interest when due, failure to comply with any covenants or conditions, failure to observe or comply with any financial covenant, a change of control of the Trust or certain subsidiaries and other standard events which are typical of credit facilities. The trust has also agreed to indemnify the Lenders in certain circumstances.

In addition, Provident’s U.S. subsidiaries have credit facilities with a borrowing base of U.S. $737.7 million with a syndicate of U.S. banks secured by oil and gas assets of the subsidiaries. Provident’s U.S. subsidiaries may draw upon the facility by way of U.S. base rate loans, LIBOR loans or letters of credit. The facilities have a termination date of October 10, 2010. At December 31, 2007, $375.4 million was drawn on these facilities.

A copy of the Canadian Credit Facility has been filed on SEDAR and is available under the Trust's issuer profile on SEDAR at www.sedar.com.

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Meetings of Unitholders

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

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

Termination of the Trust

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

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

Trust Unit Option Plan

The Trust discontinued its trust unit option plan as of May 2, 2005. No options were issued under the Option Plan after March 2005 and the Trust does not intend to issue any further options under the Option Plan in the future. However, options to acquire Trust Units previously granted under the Option Plan will continue to remain exercisable in accordance with their terms. Additional information concerning the Option Plan is included in the Trust's Proxy Statement and Information Circular dated March 27, 2008. As of March 19, 2008, there were 1.2 million options granted and outstanding under the Option Plan.

Premium Distribution, Distribution Reinvestment and Optional Unit Purchase Plan

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distribution, or (c) purchase new Trust Units under the optional unit purchase plan at a subscription price of 100 percent of the average market price of the Trust Units. If a participant has elected either (a) or (b), the plan agent may, on behalf of such participant, purchase additional Trust Units with the cash distributions at the market value of such Trust Units. Residents of Canada are eligible to elect options (a), (b), or (c). Due to regulatory restrictions, residents of the United States are eligible to elect option (a) only at this time. See "Premium Distribution, Distribution Reinvestment and Optional Unit Purchase Plan" in this Renewal Annual Information Form.

Taxation of the Trust

The Trust is a unit trust and a mutual fund trust for purposes of the Tax Act. The legislation implementing the proposals announced by the Department of Finance on October 31, 2006 respecting the taxation of certain "specified investment flow-through" ("SIFT") trusts and SIFT partnerships and their unitholders (the "SIFT Rules") received Royal Assent and became law on June 22, 2007. The SIFT Rules impose a tax at the entity level on distributions of certain income from SIFT trusts (which would include the Trust) and partnerships at a rate of tax comparable to the combined federal and provincial corporate tax and to treat such distributions as dividends to the Unitholder. Existing SIFT trusts will have a four-year transition period, and subject to the qualifications below, will not be subject to the SIFT Rules until January 1, 2011. The application of such legislation is expected to result in adverse tax consequences to the Trust and certain Unitholders, including most particularly Unitholders that are tax deferred trusts (such as registered retirement savings plans, registered retirement income funds, deferred profit sharing plans and registered education savings plans) and non-residents of Canada, and may impact cash distributions from the Trust.

Pursuant to the SIFT Rules, commencing January 1, 2011 (provided the Trust only experiences "normal growth" and no "undue expansion" before then) certain distributions from the Trust which would have otherwise been taxed as ordinary income generally will be characterized as dividends in addition to being subject to tax at corporate rates at the Trust level. Returns of capital generally are (and under the SIFT Rules will continue to be) tax-deferred for Unitholders who are resident in Canada for purposes of the Tax Act (and reduce such Unitholder's adjusted cost base in the Trust Unit for purposes of the Tax Act). Distributions, whether of income or capital to a Unitholder who is not resident in Canada for purposes of the Tax Act, or that is a partnership that is not a "Canadian partnership" for purposes of the Tax Act, generally will be subject to Canadian withholding tax.

Management believes that the SIFT Rules could impair the value of the Trust Units, which would be expected to increase the cost to the Trust of raising capital in the public capital markets. In addition, management believes that the SIFT Rules could: (a) reduce the competitive advantage that the Trust and other Canadian trusts enjoy relative to their corporate peers in raising capital in a tax-efficient manner, and (b) place the Trust and other Canadian trusts at a competitive disadvantage relative to similar industry competitors such as U.S. master limited partnerships. The SIFT Rules may make the Trust Units less attractive as an acquisition currency. As a result, it may become more difficult for the Trust to compete effectively for acquisition opportunities. There can be no assurance that the Trust will be able to reorganize its legal and tax structure to substantially mitigate the expected impact of the SIFT Rules.

The original proposals indicated that there is no intention to inhibit "normal growth" of a SIFT during the transition period, but "undue expansion" could result in the transition period being "revisited" presumably with the loss of the benefit to the SIFT of that transitional period. As a result, the adverse tax consequences associated with the SIFT Rules could be realized by the Trust sooner than January 1, 2011. The SIFT Rules provide that "normal growth" would include equity growth within certain "safe harbour" limits, measured by reference to a SIFT trust's market capitalization as of the end of trading on October 31, 2006 (which would include the SIFT's issued and outstanding publicly traded trust units and not any convertible debt, options or other interests convertible into or exchangeable for trust units). Those safe harbour limits are 40 percent for the period from November 1, 2006 to December 31, 2007, and 20

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percent for each calendar 2008, 2009 and 2010. Moreover, these limits are cumulative, so that any unused limit for a period carries over into the subsequent period. Additional details of the normal growth constraints include the following:

(a)	new equity for these purposes includes units and debt that is convertible into units (and may include other substitutes for equity if attempts are made to develop such substitutes);

(b)	replacing debt that was outstanding as of October 31, 2006 with new equity, whether by a conversion into trust units of convertible debentures or otherwise, will not be considered growth for these purposes and will therefore not affect the safe harbour limits;

(c)

the exchange for trust units, of exchangeable partnership units or exchangeable shares that were outstanding on October 31, 2006 will not be considered growth for those purposes and will therefore not affect the safe harbour where the issuance of the trust units is made in satisfaction of the exercise of the exchange right by a person other than the SIFT; and

(d)	the ability to acquire other trusts without impacting normal growth rules.

The Trust's market capitalization as of the close of trading on October 31, 2006, having regard only to its issued and outstanding publicly-traded Trust Units, was approximately $2,776 million, which means the Trust's "safe harbour" equity growth amount for the period ending December 31, 2007 is approximately $1,110 million and for each of calendar 2008, 2009 and 2010 is an additional approximately $555 million (in any case, not including equity issued to replace debt that was outstanding on October 31, 2006).

While these guidelines are such that it is unlikely they would affect the Trust's ability to raise the capital required to maintain and grow its existing operations in the ordinary course during the transition period, they could adversely affect the cost of raising capital and the Trust's ability to undertake more significant acquisitions. See "Risk Factors - General Risk Factors".

Limitation on Non-Resident Trust Unitholders

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

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

Provident may, at any time and from time to time, in its sole discretion, request that the Trustee make reasonable efforts, as practicable in the circumstances, to obtain declarations as to beneficial ownership, perform residency searches of shareholder and beneficial shareholder mailing address lists and take such

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other steps specified by Provident, at the cost of the Trust, to determine or estimate as best possible the residence of the beneficial owners of Trust Units.

If at any time the board of directors of Provident, in its sole discretion, determines that it is in the best interest of the Trust, Provident, notwithstanding the ability of the Trust to continue to rely on subsection 132(7)(a) of the Tax Act for the purpose of qualifying as a "mutual fund trust" under the Tax Act, may (i) require the Trustee to refuse to accept a subscription for Trust Units from, or issue or register a transfer of Trust Units to, a person unless the person provides a declaration to Provident that the Trust Units to be issued or transferred to such person will not when issued or transferred be beneficially owned by a Non-Resident; (ii) to the extent practicable in the circumstances, send a notice to registered holders of Trust Units which are beneficially owned by Non-Residents, chosen in inverse order to the order of acquisition or registration of such Trust Units beneficially owned by Non-Residents or in such other manner as Provident may consider equitable and practicable, requiring them to sell their Trust Units which are beneficially owned by Non-Residents or a specified portion thereof within a specified period of not less than 60 days.

If the Unitholders receiving such notice have not sold the specified number of such Trust Units or provided Provident with satisfactory evidence that such Trust Units are not beneficially owned by Non-Residents within such period, Provident may, on behalf of such registered Unitholder, sell such Trust Units and, in the interim, suspend the voting and distribution rights attached to such Trust Units and make any distribution in respect of such Trust Units by depositing such amount in a separate bank account in a Canadian chartered bank (net of any applicable taxes).

Any sale shall be made on any stock exchange on which the Trust Units are then listed and, upon such sale, the affected holders shall cease to be holders of Trust Units so disposed of and their rights shall be limited to receiving the net proceeds of sale, and any distribution in respect thereof deposited as aforesaid, net of applicable taxes and costs of sale, upon surrender of the certificates representing such Trust Units; (iii) delist the Trust Units from any non-Canadian stock exchange; and (iv) take such other actions as the board of directors of Provident determines, in its sole discretion, are appropriate in the circumstances that will reduce or limit the number of Trust Units held by Non-Residents to ensure that the Trust is not maintained primarily for the benefit of Non-Residents.

Redemption Right

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

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

It is anticipated that this redemption right will not be the primary mechanism for holders of Trust Units to dispose of their Trust Units. Notes which may be distributed in specie to holders of Trust Units in connection with a redemption will not be listed on any stock exchange and no market is expected to develop in such notes. Notes will not be qualified investments for trusts governed by registered retirement savings plans, registered retirement income funds and deferred profit sharing plans.

Trustee

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

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

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

Amendments to the Trust Indenture

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

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

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

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

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

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

Provident Energy Ltd.

The principal business of Provident is to manage and administer the operating activities associated with the oil and gas properties and the natural gas midstream, NGL processing and marketing business. Provident is also engaged in the acquisition, exploitation, development and production of crude oil and natural gas in the Western Canadian Sedimentary Basin. Provident currently has 670 employees, consultants and contract operators at its head office location and in several field offices within the core areas of Lloydminster, Northwest Alberta, West central Alberta, Southern Alberta, Southwest Saskatchewan, Southeast Saskatchewan, California and Wyoming and the NGL midstream facilities in Redwater and Empress, Alberta, Sarnia, Ontario, Lynchburg, Virginia and Houston, Texas.

Delegation of Authority, Administration and Trust Governance

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

Decision Making

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

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Common Shares

All of the issued and outstanding common shares of Provident are held by the Trust. Each common share of Provident entitles its holder to receive notice of and to attend all meetings of the shareholders of Provident and to one vote at such meetings. The holders of the common shares are, at the discretion of the board of directors of Provident and subject to applicable legal restrictions, entitled to receive any dividends declared by the board of directors on the common shares. All such common shares are entitled to share equally in any distribution of the assets of Provident upon the liquidation, dissolution, bankruptcy or winding-up of Provident or other distribution of its assets among its shareholders for the purpose of winding-up its affairs. Such participation is subject to the rights, privileges, restrictions and conditions attaching to any instruments having priority over the common shares.

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

Royalties

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

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

Provident is required to establish a reserve to fund future well bore and facility abandonment and environmental and reclamation obligations and liabilities (the "Reclamation Fund"). Provident currently funds this reserve at $0.30 per barrel of oil equivalent (converting gas to oil at 6:1) (in 2006 - $0.30; in 2005 - $0.30; in 2004 and 2003 - $0.25 per barrel of oil equivalent and in 2002 and prior - $0.20 per barrel of oil equivalent converting gas to oil at 10:1) produced, less current year well bore and facility abandonment and environmental and reclamation obligations and liabilities out of production revenues and other revenues for a calendar year into the Reclamation Fund.

Notes

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

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

Provident Acquisitions L.P. holds certain southeast Alberta properties and heavy oil wells. Holdings Trust holds all limited growth units in Provident Midstream L.P., and a 99 percent interest in Provident Marketing L.P. and Provident Acquisitions L.P. and is managed by Provident. Holdings Trust is wholly-owned by the Trust. The general partner of Provident Acquisitions L.P. is Provident. Provident Acquisitions L.P. has granted a royalty to the Trust entitling the Trust to receive the cash flow from all present and future oil and gas properties and related tangibles owned by Provident Acquisitions L.P. after certain cost expenditures and deductions. The general partner of Provident Marketing L.P. is Provident Marketing Inc. and the general partner of Provident Midstream L.P. is Provident GP Inc. Provident Midstream L.P. holds, either directly or indirectly through partnerships, all of the assets located in Canada

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acquired as a result of the Midstream NGL Acquisition, other than minor general partnership interests held by Provident GP Inc., a wholly-owned subsidiary of Provident. Cash flow from these assets flows to Holdings Trust by way of distributions on limited partnership units and from Holdings Trust to the Trust by way of interest and principal payments on notes issued by Holdings Trust to the Trust.

Provident Energy Resources Inc.

PERI holds the oil and gas assets acquired on the acquisition of Capitol Energy Resources Ltd. and Triwest Energy Inc. PERI has granted a royalty to the Trust to receive the cash flow from all present and future oil and gas properties and related tangibles owned by PERI.

Provident Acquisitions Inc.

PAI holds certain Alberta and Saskatchewan properties that were acquired through the purchase of Meota Resources Corp. PAI is managed by Provident and has 67 percent interest in 10101150 Saskatchewan Ltd. and a 0.00001 percent interest in Meota (2000) Partnership. 10101150 Saskatchewan Ltd. holds a 59.9999 percent interest in the Meota (2000) Partnership. Provident holds a 40 percent interest in the Meota (2000) Partnership. PAI has granted a royalty to the Trust entitling the Trust to receive the cash flow from all present and future oil and gas properties and related tangibles owned by PAI after certain cost expenditures and deductions.

Provident Midstream Inc.

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

Pro Holding Company

PHC owns all of the outstanding shares of Pro LP Corp. and Pro GP Corp. which in turn own approximately 96 percent of the outstanding partnership interests in BEC L.P. and approximately 22 percent of the outstanding partnership interests of BreitBurn MLP. PHC also owns all of the shares of Pro US LLC and Pro Midstream Company which in turn hold all of the partnership interests in the Kinetic Resources U.S.A. partnership. Pro US LLC holds all of the assets located in the U.S. acquired as a result of the Midstream NGL Acquisition, other than those held by the Kinetic Resources U.S.A. partnership. PHC also owns all of the common shares of PMI.

BreitBurn Energy Company L.P.

BEC L.P. holds certain of the oil and gas properties in California acquired pursuant to the BreitBurn Acquisition and the Orcutt Hill Properties acquired pursuant to the Orcutt Hill Acquisition. The Trust currently indirectly holds approximately 96 percent of the outstanding partnership interests of BEC L.P. with the remaining approximately 4 percent 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 BEC L.P. is distributed to BEC L.P.'s partners, BreitBurn Energy Corporation, Pro LP Corp. and Pro GP Corp. and from Pro LP Corp. and Pro GP Corp. to the Trust in the form of dividends, debt repayments and interest payments on intercompany debt.

BEC L.P. continues to operate and report as a business line of the Trust.

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BreitBurn Energy Partners L.P.

The assets of BreitBurn MLP consist primarily of crude oil reserves in the Los Angeles basin in California and the Wind River and Big Horn basins in central Wyoming, as well as Texas and Florida, and gas reserves in Michigan, Indiana and Kentucky. BreitBurn MLP also holds the membership interests of Nautilus, which holds oil and gas producing properties in the State of Wyoming. BreitBurn MLP is a publicly traded master limited partnership managed by its general partner, BreitBurn GP LLC, whose board of directors consists of 3 directors or officers of Provident and 4 independent directors.

The Trust indirectly holds approximately 22 percent of the outstanding partnership interests in BreitBurn MLP. The co-founders and co-chief executive officers of BEC L.P. hold approximately 1 percent of the partnership interests in BreitBurn MLP, with the public holding the remaining 77 percent of the partnership interests in BreitBurn MLP. The limited partnership units are listed for trading on the NASDAQ.

Cash flow from the assets held by BreitBurn MLP is distributed to Pro LP Corp. and Pro GP Corp. and from Pro LP Corp. and Pro GP Corp. to the Trust (via PHC) in the form of dividends, debt repayments and interest payments.

GENERAL DEVELOPMENT OF THE BUSINESS OF THE TRUST AND PROVIDENT

The following information describes the development of the business of the Trust and its material subsidiaries over the last three completed financial years.

On February 9, 2005, BEC L.P., entered into a membership interest purchase and sale agreement with all of the holders of membership interests in Nautilus pursuant to which BEC L.P. agreed to acquire all membership interests in Nautilus for an aggregate purchase price of US$75.0 million, subject to adjustment. The Nautilus Acquisition was completed on March 2, 2005.

In connection with the Nautilus Acquisition, the Trust completed a public offering on March 1, 2005 of 8,400,000 Trust Units and $100.0 million aggregate principal amount of Initial 6.5 Percent Debentures for gross proceeds of $200.0 million. The net proceeds from the offering were used to fund the Nautilus Acquisition, to fund the Trust's capital expenditure program and for general corporate purposes.

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

On May 31, 2005, all outstanding 10.5 percent convertible unsecured subordinated debentures of the Trust (the "10.5 Percent Debentures"), were redeemed at an amount of $1,050 plus all accrued and unpaid interest to May 30, 2005 per each $1,000 principal amount of 10.5 Percent Debenture. An aggregate of $3.0 million was paid on redemption of the 10.5 Percent Debentures. An aggregate of 3,507,570 Trust Units were issued upon conversion of the then outstanding 10.5 Percent Debentures prior to the redemption of such debentures.

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

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

On October 20, 2005, the Trust signed an agreement with a large oil and gas company to provide rail offloading and terminalling services for condensate to be used as a heavy oil diluent. A new condensate offloading facility was built at Provident's NGL fractionation plant at Redwater, Alberta. The existing Redwater plant has been expanded to offload and re-deliver an additional 60,000 barrels per day of condensate for the counterparty and other heavy oil producers. The expansion also included a new multi-product truck loading facility. These new terminals complement the existing pipeline connections to and from the plant and were completed in the second quarter of 2006, at a total cost of approximately $50 million. Full utilization of this facility's capacity is expected by management of Provident to increase the current western Canadian diluent supply by more than 15 percent.

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On October 27, 2005, the Trust and Provident entered into a purchase and sale agreement with EnCana Corporation, 1140102 Alberta Ltd., EnCana Midstream Inc., WD Energy Services Inc. and EnCana Kerrobert Pipelines Limited (collectively, the "EnCana Vendors") pursuant to which Provident agreed to acquire certain assets, shares and partnership interests which comprised the EnCana Vendors' natural gas liquids business for a purchase price, net of cash acquired, of $773.0 million. The assets of the Midstream NGL Business include interests in certain NGL extraction plants, pipelines, storage and fractionation facilities, distribution facilities, contracts and the EnCana Vendors' interest in the NGL marketing business operated by Kinetic Resources U.S.A., a partnership formed under the laws of the State of Michigan and Kinetic Resources (LPG), a partnership formed under the laws of the Province of Alberta. The Midstream NGL Acquisition was completed on December 13, 2005.

In connection with the Midstream NGL Acquisition, the Trust completed a public offering on November 15, 2005 of 21,830,000 subscription receipts and $150.0 million aggregate principal amount of Supplemental 6.5 Percent Debentures for gross proceeds of approximately $425.0 million. The net proceeds of the Midstream NGL Acquisition were used to pay a portion of the purchase price in respect of the Midstream NGL Acquisition. Each subscription receipt was automatically exchanged for one Trust Unit upon closing of the Midstream NGL Acquisition.

In the fourth quarter of 2005, the Trust expanded its term credit facilities from $410.0 million at December 31, 2004. The expanded facilities are comprised of $750.0 million of lending capacity related to its Canadian assets and US$100.0 million of lending capacity related to its U.S. assets. The facilities are separate and each is provided by separate syndicates of banks.

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

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

On May 12, 2006, the Trust announced that BreitBurn MLP filed a Form S-1 registration statement with the U.S. Securities and Exchange Commission in order to pursue an initial public offering.

BreitBurn MLP's assets consist primarily of producing and non-producing crude oil reserves located in the Los Angeles Basin in California and the Wind River and Big Horn Basins in Wyoming, which were transferred into BreitBurn MLP from BEC L.P. The Los Angeles based management team continues to operate both BreitBurn MLP and BEC L.P. The Trust used the net proceeds of U.S. $115.2 million from the initial public offering of BreitBurn MLP to pay down debt in Canada and the U.S.

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Effective June 30, 2006, Randall J. Findlay, the President of Provident, retired from his management responsibilities with Provident. Mr. Findlay remains on the board of directors of Provident. Thomas W. Buchanan, the Chief Executive Officer of Provident, was also appointed President of Provident following Mr. Findlay's resignation.

On July 11, 2006, Provident entered into a purchase and sale agreement (the "Purchase and Sale Agreement"), as well as certain related agreements, with a privately owned U.S. based oil and gas company and certain of its affiliates, which provided for the acquisition of certain oil and natural gas properties (the "Rainbow Assets"), through a series of steps which included the acquisition of certain partnership interests and the subsequent distribution of the Rainbow Assets to Provident out of such partnerships, for a purchase price of approximately $473.0 million. The acquisition closed on August 31, 2006.

The Rainbow Assets consist of oil, natural gas and natural gas liquids assets located in northwestern Alberta with production weighted approximately 90 percent natural gas and 10 percent light oil and NGLs, which as at June 1, 2006 were producing approximately 33 million cubic feet of gas equivalent per day (5,500 barrels of oil equivalent per day), before deduction of royalties owed to others (comprised of approximately 30.5 million cubic feet per day of natural gas and 420 barrels per day of oil and NGLs).

Included in the Rainbow Assets were approximately 126,100 gross (81,139 net) acres of undeveloped land at an average 64 percent working interest as well as proprietary and licensed seismic (approximately 4,901 kilometres of 2D seismic data and 673 square kilometres of 3D seismic data) to assist Provident in ongoing identification and evaluation of upside potential associated with the Rainbow Assets.

The acquisition of the Rainbow Assets was partially funded by the Trust's public offering of 16,325,000 subscription receipts at a price of $13.85 per subscription receipt for proceeds of $226.1 million, which closed on July 31, 2006. Upon the closing of the acquisition, holders of subscription receipts received one Trust Unit for each subscription receipt held and, as a reduction to the purchase price in respect of such subscription receipts, $0.12 per subscription receipt held.

On October 4, 2006, BreitBurn MLP priced its initial public offering of 6,900,000 common units at U.S. $18.50 per limited partnership unit and the units began trading October 4, 2006 on the NASDAQ Global Select Market under the ticket symbol "BBEP." After this transaction, the Trust owned approximately 66 percent of BreitBurn MLP.

In May 2007, BreitBurn MLP completed two oil and gas property acquisitions, one in Florida for cash consideration of U.S. $108.1 million and one in California for cash consideration of U.S. $92.5 million. The acquisitions were financed by the issue of units by BreitBurn MLP to institutional investors, decreasing the Trust's ownership in BreitBurn to approximately 50 percent.

On May 3, 2007, the Trust entered into an acquisition agreement with Capitol Energy Resources Ltd. ("Capitol") pursuant to which the Trust agreed to make an offer to purchase all of the issued and outstanding common shares of Capitol (the "Capitol Shares"), including Capitol Shares that became outstanding upon exercise of options to purchase Capital Shares, at a price of $8.16 in cash for each Capitol Share.

In conjunction with the acquisition of Capitol, the Trust entered into a bought deal agreement with a syndicate of underwriters to issue 29,313,727 subscription receipts at a price of $12.75 per subscription receipt for gross proceeds of approximately $373.75 million. Each subscription receipt holder automatically received one Trust Unit on June 20, 2007, the date the Trust acquired the Capitol Shares.

On June 20, 2007, the Trust announced that PERI had acquired approximately 96.2% of the outstanding Capitol Shares for $8.16 in cash per share. Following the expiry of the offer, PERI acquired the remaining

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Capitol Shares pursuant to the compulsory acquisition provisions of the ABCA. The Capitol Shares were de-listed from the TSX on June 21, 2007. Effective June 21, 2007, PERI and Capitol were amalgamated with the amalgamated company continuing under the name "Provident Energy Resources Inc.".

The total cash amount paid by the Trust to purchase all of the outstanding Capitol Shares was approximately $466 million. The Trust also assumed Capital's net debt of approximately $41 million. The Trust satisfied the funding requirements for the Capitol Shares from existing credit facilities and from the proceeds of the offering of subscription receipts of the Trust.

On September 12, 2007, the Trust announced the acquisition of gas-weighted producing assets by BreitBurn MLP. BreitBurn MLP signed a definitive agreement to acquire all of the natural gas, oil and midstream assets in Michigan, Indiana and Kentucky of Quicksilver Resources Inc. ("Quicksilver") for US$750 million in cash and 21.348 million BreitBurn MLP common units. BreitBurn MLP acquired the Quicksilver gas-weighted producing assets located primarily in the Michigan Antrim Shale.

BreitBurn MLP financed the Quicksilver acquisition with a combination of a private placement of new equity, bank debt, and a vendor take-back by Quicksilver of 21.348 million common units of BreitBurn MLP. The Trust did not participate in the equity offering. The BreitBurn MLP transaction reduced the Trust's ownership in BreitBurn MLP from approximately 50 percent to approximately 22 percent. The Trust continues to control BreitBurn MLP through its 96 percent ownership of BreitBurn GP LLC, the general partner.

On October 22, 2007, the Trust entered into an acquisition agreement with Triwest Energy Inc. ("Triwest") pursuant to which the Trust agreed to make an offer to purchase all of the issued and outstanding class "A" voting common shares of Triwest (the "Triwest Shares"), including Triwest Shares that became outstanding upon exercise of options to purchase Triwest Shares, for 0.6539 Trust Units and $0.1569 in cash for each Triwest Share. Triwest was an independent company engaged in the acquisition, exploration, development and production of oil and natural gas in western Canada, with operations principally conducted in Saskatchewan.

On December 4, 2007, the Trust announced that PERI had acquired 9,533,279 of the outstanding Triwest Shares, representing approximately 99.7% of the outstanding Triwest Shares (calculated on a diluted basis), pursuant to the offer. PERI acquired the remaining Triwest Shares not deposited pursuant to the offer in accordance with the compulsory acquisition procedures of the ABCA following the expiry time. An aggregate of 6,251,149 Trust Units were issued and approximately $1.5 million in cash paid in payment of all of the outstanding Triwest Shares.

PERI and Triwest were subsequently amalgamated on December 4, 2007 with the resulting amalgamated company continuing as "Provident Energy Resources Inc."

On February 5, 2008, the Trust outlined the strategic initiatives it was undertaking respecting its investment in its U.S. businesses, BreitBurn MLP and BEC L.P. The Trust also provided an update with respect to its planning process initiated to facilitate business growth and performance and access to capital. The planning process has also been in response to the Canadian Federal Government's decision to impose growth restrictions on Canadian energy trusts and, effective 2011, to implement a tax on income trust distributions.

The Trust has initiated a strategic review process for its U.S. operations which will assess, among other things, the possible sale of the BreitBurn MLP master limited partnership units owned by the Trust, as well as the Trust's interest in BreitBurn GP LLC ("the General Partner"), the general partner of BreitBurn MLP and also its interest in BEC L.P. The Trust currently owns approximately 14.8 million units or approximately 22% of BreitBurn MLP including units held by the General Partner of which the Trust indirectly owns approximately 96%. The Trust, through a wholly owned subsidiary, indirectly owns

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approximately 96% of BEC L.P. The strategic review process will be ongoing and while it is the Trust's intention to monetize its U.S. investment, there is no certainty that this process will result in any changes to the Trust's ownership stake in its U.S. holdings. The Trust has retained a financial advisor in connection with its strategic review process.

The Trust delivered an offer to BreitBurn MLP providing BreitBurn MLP the opportunity to acquire BEC L.P. as an initial step in its strategic review process. The offer was delivered in accordance with the Trust's obligations to BreitBurn under an omnibus agreement between the Trust and BreitBurn MLP. The offer formally expired and the Trust expects to initiate a formal auction sales process respecting BEC L.P., all in accordance with the omnibus agreement.

The Trust continues to assess its business plans and corporate structure as part of its overall planning in order to optimize business performance, facilitate business growth, improve overall access to capital and enhance the cost of capital for the Trust's businesses. This planning is also required to respond to the challenges arising from the Canadian Federal Government's decision to impose growth restrictions on Canadian energy trusts and, effective 2011, to implement a tax on income trust distributions.

The Trust intends through this planning initiative to consider the most viable strategic and structural options available to the Trust with the objectives of capturing and protecting unitholder value going forward. Certain options under consideration include the separation of the oil and natural gas production and the midstream components of the Trust's Canadian business. The possible separation of the upstream and midstream businesses or other alternatives reflect the Trust's view that the full value of the component parts of the business are not currently being realized in the market. The Trust cautions that the planning required before implementation of any plans will be lengthy and complex and there is no certainty that the planning will result in significant changes to the Trust.

The Trust's planning initiatives will not impact the Trust's capital program, budget or guidance. The Trust believes the initiative confirms its belief in the high quality of its asset base, the strength of its operations and the excellence of its people. Accordingly, throughout the planning initiative, the Trust will operate its Canadian businesses in the ordinary course and continue to execute its business plan and to assess and undertake strategic growth initiatives.

RISK MANAGEMENT

General

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

With respect to the oil and gas production business, Provident is focused on the acquisition, development, exploitation, production and marketing of crude oil and natural gas. Provident's energy portfolio is located in some of the most stable and predictable producing regions in Western Canada and the United States. In management's opinion, these areas generally offer low to medium risk development potential and a well developed operational infrastructure, which is suited to a trust. Provident focuses its development activities on low risk drilling opportunities that can be used to partially offset production declines.

Provident's natural gas midstream, NGL processing and marketing business adds an additional dimension to the Trust – one with relatively small maintenance capital requirements. This provides the Trust with more stable, longer life cash flows and provides the Trust access to a broader range of growth opportunities along the energy value chain.

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A disciplined integrated risk management strategy is employed by Provident, focusing on stabilizing cash flow. To this end, Provident uses both financial and physical contracts to reduce the volatility of crude, natural gas and NGL prices.

Risk Management

Provident has a comprehensive Enterprise Risk Management program that is designed to identify and manage risks that could negatively affect its business, operations or results. The program’s activities include risk identification, assessment, response, control, monitoring and communication.

Provident’s Risk Management group executes the program with oversight from the Risk Management Committee (“RMC”), which provides regular reports to the Board of Directors.

Provident’s Risk Management group monitors risk exposure by generating and reviewing counterparty credit exposure and mark-to-market reports of its outstanding derivative contracts. Provident’s monitoring activities also include reviewing available hedging structures, regulatory changes and bank, analyst and legal reports.

The status of key risk exposures is regularly communicated to Provident’s executive and business lines. External audiences receive regular risk updates through quarterly and annual reports.

Commodity Price Risk Management Program

The decisions to enter into hedge positions and to execute risk management strategy are made by senior officers of Provident who are also members of the RMC. The RMC receives input and commodity expertise from each business unit in the decision making process. Strategies are selected based on their ability to help Provident provide stable cash flow and distributions per unit rather than to simply lock in a specific price per barrel of oil or cubic foot of natural gas.

Oil and Natural Gas Hedging

Provident’s hedging program employs derivative instruments, such as puts, participating swaps and costless collars, to protect a floor level of Provident’s EBITDA (earnings before interest, taxes, depletion, depreciation, accretion and other non-cash items) on a portion of the oil and gas sold. At the same time, these instruments enable Provident to retain various levels of participation to the extent oil and gas prices rise. Provident may also use fixed price derivative instruments for its oil and natural gas business lines to protect acquisition economics.

The major identified risks for the oil and natural gas business lines (COGP and USOGP) are commodity price volatility and market location differentials. Provident addresses these risks using a hedging program designed to protect a portion of its cash flow in order to support continued unitholder distributions, capital programs and bank financing.

Midstream Services

Commodity price volatility and market location differentials also affect the Midstream business. In addition, Midstream is exposed to possible price declines between the time Provident purchases natural gas liquid (NGL) feedstock and sells NGL products, and to narrowing frac spreads. Frac spread is the margin between the price paid for the natural gas feedstock from which Provident extracts NGLs, and the absolute price at which Provident sells NGL products (propane, butane and condensate).

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Provident responds to these risks using a hedging program that protects a margin or floor level of EBITDA on a portion of its NGL inventory and production, while retaining some ability to participate in a widening margin environment. For longer-term hedges, Provident hedges crude oil in place of NGLs. Provident may replace these hedges with actual NGL hedges as market conditions allow. This strategy enables Provident to mitigate commodity price risk related to its NGL production business up to five years into the future.

Foreign Currency & Interest Rates

Provident receives both Canadian and U.S. dollars for oil, natural gas and NGL sales, exposing it to both positive and negative effects of fluctuations in the exchange rate. Provident manages this exposure by matching a significant portion of the cash costs that it expects with revenues in the same currency. As well, Provident uses derivative instruments to manage the U.S. cash requirements of its U.S. and Canadian business lines. Provident can also manage the associated risk of higher interest rates using derivative instruments.

Provident’s foreign exchange hedging strategy reduced the effect of the 13 percent appreciation of the Canadian dollar relative to the U.S. dollar in 2007. Provident regularly sells or purchases forward a portion of expected U.S. cashflows. Provident’s strategy also manages the exposure it has to fluctuations in the U.S./Canadian dollar exchange rate when the underlying commodity price is based upon a U.S. index price. Provident may also use derivative products that provide for insurance against a stronger Canadian dollar, while allowing it to participate if the currency weakens relative to the U.S. dollar.

Power

Power is a significant cost to Provident. Provident manages volatile power costs by purchasing derivative contracts that fix the cost of power for a pre-determined time period.

Details of the financial instruments in place at December 31, 2007 are summarized in Note 13 to the Trust's audited consolidated financial statements for the year ended December 31, 2007 and are incorporated by reference herein. The Trust's audited consolidated financial statements for the year ended December 31, 2007 have been filed on SEDAR and are available under the Trust's issuer profile at www.sedar.com.

Credit Risk

Provident's Credit Policy governs the activities undertaken to mitigate the risks associated with counterparty (customer) non-payment. A formal credit review is required for counterparties entering into a commodity contract with Provident. This review determines an approved credit limit. Counterparty exposures are regularly monitored and an annual review of all active counterparties is performed. In addition, the policy sets criteria to ensure that Provident has a diversified base of creditors.

Insurance

Provident purchases property insurance, business interruption insurance, liability/pollution insurance and well control insurance to manage the risks associated with the operation of Provident's assets. Provident also purchases directors & officers insurance.

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OIL AND NATURAL GAS OPERATIONS

Provident's Canadian reserves were evaluated by McDaniel and AJM effective December 31, 2007, in accordance with NI 51-101. Provident's U.S. reserves were evaluated by NSAI and Schlumberger effective December 31, 2007 in accordance with NI 51-101. McDaniel, AJM, NSAI and Schlumberger are independent qualified reserves evaluators appointed pursuant to NI 51-101. The McDaniel evaluation report is dated February 15, 2008 with a preparation date of December 31, 2007. The AJM evaluation report is dated February 21, 2008 with a preparation date of December 31, 2007. The Schlumberger evaluation report is dated February 29, 2008 with a preparation date of December 31, 2007. The NSAI evaluation report is dated February 25, 2008 with a preparation date of December 31, 2007.

The Trust's Statement of Reserves Data and Other Oil and Gas Information on Form 51-101F1, the Report on Reserves Data by Independent Qualified Reserves Evaluator or Auditor on Form 51-101F2 from each of McDaniel, AJM, NSAI and Schlumberger dated February 15, 2008, February 21, 2008, February 25, 2008 and February 29, 2008, respectively and the Report of Management and Directors on Oil and Gas Disclosure on Form 51-101F3 dated March 6, 2008 have been filed on SEDAR at www.sedar.com and are incorporated by reference in this Renewal Annual Information Form.

NATURAL GAS MIDSTREAM, NGL PROCESSING AND MARKETING OPERATIONS

General

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

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

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

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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 percent of propane and 80 percent of butane in order to meet pipeline specifications. Most field plants do not remove ethane, but there is currently about 70,000 b/d of ethane produced from Alberta field plants out of a total 240,000 b/d of ethane production from western Canada. The NGLs extracted are generally removed in mixes (either ethane-plus or propane-plus), which must be further processed in subsequent steps to separate out the individual products. Approximately 40 percent of the 700 field plants in western Canada extract NGLs.

NGL Fractionation

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

NGL Transportation

The efficient movement of NGL products in Canada requires significant infrastructure, including transportation assets (pipelines, trucks, rail cars), storage facilities and terminals (rail and truck). The most efficient and the lowest cost means for moving NGL products to markets is by pipeline. The Canadian NGL sector has an extensive pipeline network for the transportation of natural gas to field plants and extraction facilities, and NGLs to fractionation facilities, petrochemical complexes, underground storage facilities and the final customer. Truck and rail account for a significant amount of the NGLs transported in Alberta, with pipelines serving as the main mode of transport. Provident has the capacity to move NGLs throughout North America via pipeline, truck or rail. In addition to its extensive pipeline network, Provident has long term leases on approximately 835 rail cars.

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NGL Storage

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

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

NGL Marketing

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

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

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

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

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

Commercial Arrangements

Extraction

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

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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

The Midstream business

The Midstream business unit extracts, processes, stores, transports and markets natural gas liquids (NGL) for Provident and offers these services to third party customers. The Provident Midstream segment contains three business lines.

The Empress East business line is comprised of the following core assets:

Approximately 2.0 Bcfd of extraction capacity at Empress Alberta. This is the combination of 67.5 percent ownership of the 1.2 Bcfd capacity Provident Empress NGL Extraction plant, 12.4 percent ownership in the 1.1 Bcfd capacity ATCO Plant, 8.3 percent ownership in the 2.4 Bcfd capacity Spectra Plant and 33.0 percent ownership in the 2.7 Bcfd capacity BP Empress 1 Plant.

·	100 percent ownership of a 50,000 bpd debutanizer at Empress Alberta.

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

In Sarnia, Ontario, 10.3 percent ownership of an approximately 150,000 bpd fractionator, 1.7 mmbbl of raw product storage capacity and 18 percent of 5.0 mmbbl of finished product storage and rail, truck and pipeline terminalling. An additional 0.5 mmbbls of specification product storage is also available in the Sarnia area.

·	A propane distribution terminal at Lynchburg, Virginia.

·	A rail car fleet of approximately 350 rail cars.

The income for this business line is primarily driven by the pricing relationship of natural gas at AECO to NGL values in Mont Belvieu, Texas. Provident purchases the NGLs from suppliers at Empress at gas values and then extracts the NGLs from the gas at the various straddle plants. Propane, butane and condensate prices trend on a pricing relationship to crude oil. Provident sells this product and other acquired specification product into key market areas such as Ontario, Quebec, and the Eastern Seaboard. The higher the ratio of the WTI crude oil price to the natural gas price at AECO (the fractionation spread ratio "frac spread ratio"), the higher the gross operating margin this business line will typically deliver. There has also, however, historically been a differential between propane, butane and condensate prices and crude oil prices which can change prices received and margins realized for Midstream products separate from frac spread ratio changes.

The Redwater West business line is comprised of the following core assets:

100 percent ownership of the Redwater NGL Fractionation Facility, incorporating a 65,000 bpd fractionation, storage and transportation facility that includes 12 pipeline receipt and delivery points, railcar loading facilities with direct access to CN rail and indirect access to CP rail, two propane truck loading facilities, six million gross barrels of salt cavern storage, and a 60,000 bpd condensate rail offloading facility with a 300 railcar storage yard. The facility can process high-sulphur NGL streams and is one of only two ethane-plus fractionation facilities in western Canada capable of extracting ethane from the natural gas liquids stream.

·	Approximately 7,000 bpd of leased fractionation and storage capacity at other facilities.

·	43.3 percent direct ownership and 100 percent control of all products from the 38,500 bpd Younger NGL extraction plant located at Taylor in northeastern British Columbia. The Younger Plant supplies local markets as well as Provident's Redwater plant near Edmonton.

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

·	A rail car fleet of approximately 485 rail cars.

The income for this business line includes the long term natural gas liquids purchase agreement from Taylor Gas Liquids for its share of the production at the same plant. Further, this business line includes the income generated by the supply and marketing personnel in the Calgary office which includes the

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purchasing of NGL mix from various producers transporting to Redwater/Ft. Saskatchewan for fractionation and sale to various markets primarily in Western Canada and the Western United States.

The Commercial Services business line is comprised of the following:

The Commercial Services business line includes services such as fractionation, storage, and loading at Provident's Redwater facility on a fee basis. It also includes pipeline tariff income from Provident's ownership of the Liquids Gathering System in Northwest Alberta which flows into Pembina's pipeline from LaGlace to Redwater. Provident also collects tariff income from its 50 percent ownership in the Kerrobert Pipeline which transports NGLs from Empress to Kerrobert for injection into the Enbridge pipeline for delivery to Sarnia. Further, Provident owns a debutanizer at its Empress facility, which removes condensate from the NGL mix for sale as a diluent to blend with heavy oil. This service is provided to a major energy company on a long term cost of service basis. Earnings from this business line of the Midstream segment have little direct exposure to market prices volatility and are thus relatively stable.

Long term contracts

At the Redwater facility, a significant portion of the available propane plus capacity is contracted through a long term fee for service arrangement with third parties.

In 2006 and early 2007, Provident commissioned a 60,000 bpd condensate rail off-loading terminal at Redwater, a significant portion of which is under long term contracts with two major energy producers.

The ethane produced from Provident's facilities at Empress and Redwater is largely sold under long term contracts.

Provident also has a long term contract on a cost of service basis for the majority of its 50,000 bbl/d Empress debutantizer facility and a long term contract for 500,000 barrels of specification product storage in the Sarnia area.

MARKET FOR SECURITIES

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

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

Toronto Stock Exchange

Trust Units (PVE.UN)

Period	High ($)		Low ($)		Volume (000's)
2007
January	$	12.80	$	11.63		6,255
February	$	12.75	$	12.05		4,909
March	$	13.02	$	11.93		5,366
April	$	13.57	$	12.44		6,028
May	$	13.29	$	12.41		12,590
June	$	12.87	$	12.38		10,904
July	$	12.99	$	12.17		12,893
August	$	12.63	$	11.02		13,282
September	$	12.70	$	11.85		9,723
October	$	12.70	$	11.89		10,803
November	$	12.65	$	10.07		11,194
December	$	10.58	$	9.60		13,587

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8.75 Percent Debentures (PVE.DB.A)

Period	High ($)		Low ($)		Volume
2007
January	$	110.02	$	106.18		580
February	$	114.21	$	112.70		1,470
March	$	116.46	$	113.80		960
April	$	121.34	$	113.02		1,950
May	$	117.50	$	108.77		760
June	$	114.38	$	107.92		200
July	$	115.12	$	106.52		51,730
August	$	112.00	$	108.49		270
September	$	114.00	$	112.00		600
October	$	114.81	$	108.52		1,940
November	$	111.88	$	96.66		2,140
December	$	106.00	$	97.01		1,860

8 Percent Debentures (PVE.DB.B)

Period	High ($)		Low ($)		Volume
2007
January	$	106.25	$	105.65		9,850
February	$	110.00	$	106.50		2,210
March	$	110.00	$	106.10		3,265
April	$	114.99	$	107.54		41,900
May	$	108.74	$	105.50		8,430
June	$	107.84	$	106.00		8,330
July	$	108.92	$	105.02		4,980
August	$	105.00	$	102.00		1,800
September	$	106.26	$	103.05		9,610
October	$	105.78	$	103.22		12,300
November	$	103.02	$	97.62		37,000
December	$	101.47	$	99.35		9,570

Initial 6.5 Percent Debentures (PVE.DB.C)

Period	High ($)		Low ($)		Volume
2007
January	$	102.55	$	99.99		25,390
February	$	101.74	$	100.00		25,350
March	$	101.74	$	100.26		54,140
April	$	105.77	$	100.34		25,630
May	$	102.99	$	101.42		32,420
June	$	102.75	$	101.04		6,560
July	$	102.25	$	99.51		7,340
August	$	100.48	$	97.00		31,050
September	$	99.25	$	98.00		10,060
October	$	100.99	$	97.26		33,560
November	$	99.74	$	96.00		30,920
December	$	96.79	$	90.00		4,650

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Supplemental 6.5 Percent Debentures (PVE.DB.D)

Period	High ($)		Low ($)		Volume
2007
January	$	100.99	$	98.31		28,965
February	$	99.74	$	96.09		18,370
March	$	99.99	$	97.75		1,630
April	$	101.93	$	96.26		93,490
May	$	101.79	$	100.00		20,480
June	$	101.99	$	98.00		22,150
July	$	101.19	$	97.01		8,320
August	$	99.43	$	93.26		7,630
September	$	99.49	$	96.01		6,930
October	$	98.74	$	95.01		10,270
November	$	98.74	$	93.51		31,890
December	$	96.25	$	90.00		44,490

New York Stock Exchange

Trust Units (PVX)

Period	High (U.S.$)		Low (U.S.$)		Volume (000's)
2007
January	$	10.94	$	9.97		22,041
February	$	10.89	$	10.34		15,260
March	$	11.24	$	10.10		17,107
April	$	12.08	$	10.76		18,623
May	$	12.00	$	11.54		22,743
June	$	12.20	$	11.61		20,193
July	$	12.45	$	11.70		18,618
August	$	12.00	$	10.00		21,773
September	$	12.73	$	11.37		17,494
October	$	13.25	$	12.12		17,925
November	$	13.55	$	10.05		27,850
December	$	10.55	$	9.65		29,282

RECORD OF CASH DISTRIBUTIONS

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

Distribution Amount

(Cdn$)

Distribution Amount

(US$)(1)

2001 March - December	$2.54	$1.64

2002 January - December	$2.03	$1.29

2003 January - December	$2.06	$1.47

2004
January - December	$1.44	$1.10

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Distribution Amount

(Cdn$)

Distribution Amount

(US$)(1)

2005
January - December	$1.44	$1.20

2006
January - December	$1.44	$1.26

2007
January - December	$1.44	$1.35

2008
January	$0.12	$0.12
February	$0.12	$0.12
March	$0.12	$0.12
Total to date for 2008	$0.36	$0.36

Since its inception, the Trust has paid an aggregate of $12.75 (U.S.$9.67) in cash distributions to Unitholders.

Note:

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

PREMIUM DISTRIBUTION, DISTRIBUTION REINVESTMENT

AND OPTIONAL UNIT PURCHASE PLAN

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

The Plan was implemented in May 2002. The following table provides the details of the DRIP since January 2006.

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		Premium Distribution	5 percent Discounted Unit Price for Distribution Reinvestment Purchase Plans
Payable Date	Regular Distribution	102 percent of Regular Distribution(1)	15 Day Weighted Average Unit Price(2)	5 percent Discounted Unit Price
14-March-08	$0.12	$0.1224	$10.6251	$10.0938
15-Feb-08	$0.12	$0.1224	$10.1047	$9.5995
15-Jan-08	$0.12	$0.1224	$10.0892	$9.5847
14-Dec-07	$0.12	$0.1224	$10.3798	$9.8608
15-Nov-07	$0.12	$0.1224	$12.2344	$11.6227
15-Oct-07	$0.12	$0.1224	$12.5390	$11.9121
14-Sept-07	$0.12	$0.1224	$12.1125	$11.5069
15-Aug-07	$0.12	$0.1224	$12.3412	$11.7241
13-Jul-07	$0.12	$0.1224	$12.6583	$12.0254
15-Jun-07	$0.12	$0.1224	$12.6321	$12.0005
15-May-07	$0.12	$0.1224	$13.0121	$12.3615
13-Apr-07	$0.12	$0.1224	$12.7197	$12.0837
15-Mar-07	$0.12	$0.1224	$12.3966	$11.7768
15-Feb-07	$0.12	$0.1224	$12.3681	$11.7497
13-Jan-07	$0.12	$0.1224	$12.2272	$11.6158
15-Dec-06	$0.12	$0.1224	$12.6249	$11.9937
15-Nov-06	$0.12	$0.1224	$12.1807	$11.5717
14-Oct-06	$0.12	$0.1224	$12.7208	$12.0848
15-Sept-06	$0.12	$0.1224	$14.0002	$13.3002
15-Aug-06	$0.12	$0.1224	$13.9400	$13.2430
15-Jul-06	$0.12	$0.1224	$13.8654	$13.1721
15-Jun-06	$0.12	$0.1224	$13.7283	$13.0419
13-May-06	$0.12	$0.1224	$13.3193	$12.6533
15-Apr-06	$0.12	$0.1224	$13.1042	$12.4490
15-Mar-06	$0.12	$0.1224	$12.3241	$11.7079
15-Feb-06	$0.12	$0.1224	$12.3995	$11.7795
14-Jan-06	$0.12	$0.1224	$12.8715	$12.2279

Notes:

(1)	If, in respect of any distribution payment date, fulfilling all of the elections under the DRIP would result in Provident exceeding either the limit on new equity set by Provident or the aggregate annual limit on new Trust Units issuable pursuant to optional cash payments, then elections for the purchase of new Trust Units on that distribution payment date will be accepted: (i) first, from participants electing to reinvest their cash distributions in new Trust Units under the distribution reinvestment component of the DRIP; (ii) second, from participants electing to make optional cash payments; and (iii) third, from participants electing to receive the premium distributions. If Provident is not able to accept all elections in a particular category, then purchases of Trust Units in that category on the applicable distribution payment date will be prorated among all participants in that category according to the number of additional Trust Units sought to be purchased. Therefore, amounts shown in the table represent maximum amounts payable and actual amounts paid may be less due to proration.

(2)	This is the price used for purchases made under the DRIP.

Materials relating to the DRIP are available on SEDAR at www.sedar.com or the Trust's website at www.providentenergy.com or by contacting Provident by phone at (403) 296-2233 or by mail at 2100, 250 - 2nd Street S.W., Calgary, Alberta T2P 0C1.

DIRECTORS AND OFFICERS

The following are the names and municipality of residence of the directors and officers of Provident, their principal position with Provident and their principal occupations. The Trust does not have any directors or officers. All of the persons listed below have been engaged for more than five years in their present principal occupation or executive position with the same or associated companies except as indicated below. Each of the directors below will remain in office until the next annual meeting of Unitholders scheduled on May 8, 2008.

- 39 -

Name and Background		Number of Trust Units Beneficially Owned or Controlled or Directed
John B. Zaozirny(2) of Calgary, Alberta is Chairman of the Board. He also serves as counsel to the law firm of McCarthy Tétrault llp and Vice-Chairman of Canaccord Capital Corporation. He has been a director of Provident since 2001 and is also a director of Bankers Petroleum Ltd., Canadian Oil Sands Trust, Coastal Energy Company, Computer Modelling Group Ltd., Candax Inc., Fording Canadian Coal Trust, IPSCO Inc., Pengrowth Energy Trust and TerraVest Income Fund.		60,336

Grant D. Billing(2) of Calgary, Alberta is the Chairman and Chief Executive Officer and a director of Superior Plus Inc., a diversified trust, since 1998. He has been a director of Provident since 2001. He is also a director of BreitBurn Energy Partners LP.		100,000(4)

Thomas W. Buchanan of Calgary, Alberta has been the Chief Executive Officer and a director of Provident since March 2001. Mr. Buchanan has also been the President of Provident since June 30, 2006. Prior thereto he was Executive Vice President Corporate Development and Chief Financial Officer of Founders Energy Ltd. from October 1999 to March 2001. He is also a director of Churchill Energy Inc., Athabasca Oilsands Corp. and BreitBurn Energy Partners LP.		930,696(4)

Hugh A. Fergusson(1)(3) of Calgary, Alberta is the former Vice President and Director with Dow Chemical Canada Inc. He has been a director of Provident since 2005 and is also a director of Canexus Income Fund.		5,000(4)

Randall J. Findlay(3) of Calgary, Alberta has been a director of Provident since March 2001. Mr. Findlay was also the President of Provident from March 2001 until June 30, 2006. Prior thereto he was Executive Vice President and Chief Operating Officer of Founders Energy Ltd. from December 1999 to March 2001. He is also a director of Canadian Helicopters Income Fund, Ellis Don, Pembina Pipelines Income Fund, Superior Plus Inc. and BreitBurn Energy Partners LP.		745,378

Norman R. Gish(2) of Calgary, Alberta is an independent businessman. Prior thereto, he was Chairman, President and Chief Executive Officer of Alliance Pipeline Ltd. and Aux Sable Liquid Products Inc. He has been a director of Provident since 2003 and is also a director of Railpower Technologies Corp. and Superior Plus Inc.		7,000(4)

Bruce R. Libin(1)(3) of Calgary, Alberta is the Executive Chairman and Chief Executive Officer of Destiny Resource Services Corp., a resource services company, since December 2000. He has also been President of B.R. Libin Capital Corp., an investment, merchant banking and investment banking advisory services company since 1995. He has been a director of Provident since 2001 and is also Chairman of Winstar Resources Ltd.		140,626

Dr. Robert W. Mitchell(3) of Calgary, Alberta has been an independent businessman since September 2003. From 1984 to September 2003, he was Executive Vice President of Talisman Energy Inc., a public oil and gas company. He has been a director of Provident since 2004 and is also a director of Winstar Resources Ltd.		26,000

M.H. (Mike) Shaikh(1) of Calgary, Alberta is a chartered accountant. He has been a director of Provident since 2001 and is also a director of Churchill Energy Inc. and BNP Resources Inc.		139,610(4)

Jeffrey T. Smith(2)(3) of Calgary, Alberta is an independent businessman. He has been a director of Provident since 2001 and is also a director of Compton Petroleum Ltd. and Cordero Energy Inc.		10,900

Notes:

(1)	Member of the Audit Committee.
(2)	Member of the Governance, Human Resources and Compensation Committee.
(3)	Member of the Reserves, Operations and Environment, Health and Safety Committee.
(4)	Mr. Billing also holds $792,000 principal amount of the Initial 6.50 Percent Debentures. Mr. Buchanan also holds $100,000 of the Supplemental 6.50 Percent Debentures. Mr. Fergusson also holds $100,000 of the Supplemental 6.50 Percent Debentures. Mr. Shaikh also holds $250,000 principal amount of the Supplemental 6.50 Percent Debentures. Mr. Gish also holds $20,000 principal amount of the 8.75 Percent Debentures and also holds $110,000 principal amount of the Supplemental 6.50 Percent Debentures.

- 40 -

Murray N. Buchanan

Co-President, Midstream Business Unit

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

Andrew G. Gruszecki

Co-President, Midstream Business Unit

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

David I. Holm

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

Mr. Holm received his Bachelor of Commerce Degree from the University of Alberta and his Bachelor of Laws Degree from the University of Western Ontario. He was called to the Alberta Bar in 1986. Mr. Holm has spent six years as a senior banker and most recently was Managing Director, North American Energy with TD Securities Inc. prior to joining Provident in 2006. Prior to his move into investment banking, Mr. Holm practiced securities law for 15 years, most recently as a partner with Macleod Dixon LLP.

Gary R. Kline

Senior Vice President, Commercial Development and Risk Management

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

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Daniel J. O'Byrne

Executive Vice President, Operations and Chief Operating Officer

Mr. O'Byrne received his Bachelor of Science Degree in Petroleum Engineering from the University of Alberta and a Masters of Business Administration Degree from the University of Western Ontario. Mr. O'Byrne has over 25 years of diverse experience in the international and North American oil industry and has participated in major projects in Canada, the United Kingdom (North Sea), the Middle East, West Africa and other countries. Mr. O'Byrne held various executive positions with Nexen and its predecessor, Canadian Occidental Petroleum Ltd. from 1997 to 2005. He is also a former director of the Petroleum Technology Research Centre, a director of Unbridled Energy Ltd., and a past chair of the Canadian Oil Sands Network for Research and Development. He has contributed to the reserves and safety committees of the Canadian Association of Petroleum Producers, is a member of the Association of Professional Engineers, Geologists and Geophysicists of Alberta and is one of the Society of Petroleum Engineers published authors.

Lynn M. Rannelli

Assistant Corporate Secretary

Ms. Rannelli received her Business Management Certificate from the University of Calgary. Ms. Rannelli joined Provident in 2001, following the acquisition of Maxx Petroleum Ltd. and has over 20 years of experience in Corporate Administration, Human Resources, Records Management, Investor Relations and Communications. Ms. Rannelli is a member of the Canadian Society of Corporate Secretaries.

Cameron G. Vouri

President, Canadian Oil and Gas Production Business Unit

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

Mark N. Walker

Senior Vice President, Finance and Chief Financial Officer

Mr. Walker received his Bachelor of Commerce in Accounting from the University of Calgary and later received his Certified Management Accountant designation. Mr. Walker began his career in 1988 and held positions of increasing responsibility prior to joining Founders Energy in 1996 as Controller. Prior to the appointment to his current position, Mr. Walker was Vice President Finance and Chief Financial Officer of Provident since March 2001. Mr. Walker has over 20 years of experience in petroleum finance and accounting.

Committees of the Board

During the year ended December 31, 2007, the Board of Directors had three committees – the Audit Committee, the Reserves, Operations and Environmental, Health and Safety Committee and the Governance, Human Resources and Compensation Committee. In addition, the Trust has established one additional committee in 2006 – the Disclosure Committee, which is comprised entirely of members of management. Membership in each committee is set forth below.

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Audit Committee

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

Governance, Human Resources and Compensation Committee

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

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

Reserves, Operations, Environment, Health and Safety Committee

The Reserves, Operations and Environmental, Health and Safety Committee consists of Mr. Jeffrey T. Smith (Chairman), Dr. Robert Mitchell, Mr. Bruce R. Libin, Mr. Byron J. Seaman, Mr. Hugh A. Fergusson and Randall J. Findlay, all of whom are considered independent directors, other than

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Mr. Findlay, within the meaning of applicable securities legislation. The Committee assists the board in its oversight of the oil and natural gas reserves evaluation process and the public disclosure of reserves data and related information as required by National Instrument 51-101; the operations of Provident, including operating activities, operating expenses and capital expenditure budget; and the environmental, health and safety issues, including the evaluation of Provident's programs, controls and reporting systems, and compliance with applicable laws, rules and regulations.

Disclosure Committee

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

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

Conflicts of Interest

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

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

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AUDIT COMMITTEE INFORMATION

Composition of the Audit Committee

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

Audit Committee Charter

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

Relevant Education and Experience of Each Audit Committee Member

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

Name	Independent	Financially Literate	Relevant Education and Experience

M.H. (Mike) Shaikh, FCA	Yes	Yes	Mr. Shaikh holds the degree of Bachelor of Commerce and is a Chartered Accountant. As a Chartered Accountant, Mr. Shaikh attained experience in preparing, auditing, analyzing and evaluating financial statements. Mr. Shaikh has an understanding of the accounting principles used by Provident as well as the implications of those accounting principles on Provident's financial results. Mr. Shaikh has also obtained significant financial experience and exposure to accounting and financial issues as the President of M.H. Shaikh Professional Corporation and in his role as a director and audit committee member of various public companies. He was also a board member of the Alberta Securities Commission from 2003 to 2006.

Bruce R. Libin, Q.C.	Yes	Yes	Mr. Libin holds the degree of Bachelor of Commerce (Honours), Master of Business Administration and Juris Doctoris. Mr. Libin has obtained significant financial experience and exposure to accounting, disclosure, internal controls and financial issues during his legal practice, his business experience (including as Chief Executive Officer of Beau Canada Exploration Ltd. and as Executive Chairman and Chief Executive Officer of Destiny Resource Services Corp.) and his service on the audit committee of several boards of directors, including Amoco Canada Petroleum Company Limited, Maxx Petroleum Ltd., Mark's Work Warehouse Ltd., Calgary Health Region, Southern Alberta Institute to Technology, NQL Drilling Tools Ltd., and Winstar Resources Ltd.

Hugh A. Fergusson, LLB	Yes	Yes	Mr. Fergusson holds the degrees of Bachelor of Arts and Bachelor of Laws. He has also completed Advanced Management Programs at the University of Western Ontario and Northwestern University. He is an independent businessman and Corporate Director. Mr. Fergusson practiced law for five years following which he was employed by the Dow Chemical Company (and related companies) for 27 years until he retired in 2004. During his career with Dow, Mr. Fergusson obtained significant financial experience and exposure to accounting and financial issues through a series of roles including commercial and business leadership largely related to hydrocarbons and energy. In addition to being a director of a number of Dow subsidiaries, Mr. Fergusson was Chairman of Petromont Inc. from 2002 until 2004 and a member of its Audit Committee from 2002 until 2004.

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External Auditor Service Fees

The following table sets forth information about the fees billed to the Trust and its Canadian and U.S. subsidiaries for professional services provided by PricewaterhouseCoopers llp during fiscal 2007 and 2006. PricewaterhouseCoopers llp is independent in accordance with the auditor's rules of professional conduct in Canada.

(CDN$)	2007		2006
Audit Fees	$	2,893,800	$	2,680,800
Audit-Related Fees		590,600		1,244,900
Tax Fees		675,900		1,207,500
All Other Fees		173,300		-
Total	$	4,333,600	$	5,133,200

Audit Fees

Fees for audit services totalled approximately $2.9 million in 2007 and approximately $2.7 million in 2006, including fees associated with the annual audit, the reviews of the Trust's quarterly reports, statutory audits and regulatory filings. These fees include approximately $1.7 million in 2007 and $1.5 million in 2006 directly related to U.S. operations. Fees in 2007 have increased as a result of growth in the Trust by acquisition.

Audit-Related Fees

Fees for audit-related services totalled approximately $0.6 million in 2007 and approximately $1.2 million in 2006. Audit related services include consultations concerning documents filed with respect to audits in connection with proposed or completed acquisitions and for 2007 included work related to BreitBurn MLP.

Tax Fees

Fees for tax services totalled approximately $0.7 million in 2007 and approximately $1.2 million in 2006. Fees for tax services include tax compliance, tax planning and tax advice services.

All Other Fees

Fees for all other services totalled approximately $0.2 million in 2007.

The Trust has complied with applicable rules regulating the provision of non-audit services to the Trust by its external auditor. All audit and non-audit services provided to the Trust by PricewaterhouseCoopers llp in excess of $100,000 have been pre-approved by the Audit Committee. The Audit Committee has reviewed these services to ensure they are compatible with maintaining the independence of the external auditor.

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INFORMATION CONCERNING THE OIL AND GAS INDUSTRY

Canadian Government Regulation

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

Pricing and Marketing - Oil

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

Pricing and Marketing - Natural Gas

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

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

The North American Free Trade Agreement

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

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

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Provincial Royalties and Incentives

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

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

The Government of Alberta receives royalties on the production of natural resources from lands in which it owns the mineral rights. On October 25, 2007, the Government of Alberta unveiled a new royalty regime. The new regime will introduce new royalties for conventional oil, natural gas and bitumen effective January 1, 2009 that are linked to price and production levels and will apply to both new and existing conventional oil and gas activities and oil sands projects.

Royalties payable pursuant to petroleum and natural gas leases with the Government of Alberta are ad valorem royalties, assessed on a sliding scale where the rate changes depending on oil or natural gas prices and the level of production. Royalties payable to the Crown in right of the Province of Alberta (the "Crown") currently are 30 and 35 percent in the case of old and new conventional oil, respectively, from 5 to 35 percent in the case of natural gas, and from 15 to 50 percent in the case of natural gas liquids.

Under the new royalty regime, it is proposed that the royalty for conventional oil will be determined based upon a sliding rate formula containing elements that account for oil price and well production, and specialty royalty programs will be eliminated along with "old" and "new" tiers. Royalty rates for conventional oil will range up to 50 percent, with rate caps once the price of conventional oil reaches Cdn.$120 per barrel.

Under the new royalty regime, it is proposed that natural gas royalties will be set by a sliding rate formula sensitive to price and well production, and vintages will be eliminated along with certain specialty royalty programs, though a form of deep gas royalty holiday will be retained and lower royalty rates will be applied over a wider price range for wells with less productivity. Royalty rates for natural gas will range from five percent to 50 percent with rate caps once the price of natural gas reaches $16.59/gj. A shallow rights reversion program will also be implemented that will result in the reversion to the Crown in Alberta of mineral rights to underdeveloped geological formations above developed zones. Royalties for natural gas liquids will be set at 40 percent for pentanes and 30 percent for butanes and propane.

The implementation of the proposed changes to the royalty regime in Alberta is subject to certain risks and uncertainties. The significant changes to the royalty regime require new legislation, changes to existing regulations and development of proprietary software to support the calculation and collection of royalties. Additionally, certain proposed changes contemplate further public and/or industry consultation. There may be modifications introduced to the proposed royalty structure prior to the implementation thereof.

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Environmental Regulation

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

In December, 2002, the Government of Canada ratified the Kyoto Protocol (the "Protocol"). The Protocol calls for Canada to reduce its greenhouse gas emissions to 6% below 1990 "business as usual" levels between 2008 and 2012. Given revised estimates of Canada's normal emissions levels, this target translates into an approximately 40% gross reduction in Canada's current emissions. It remains uncertain whether the Kyoto target of 6% below 1990 emission levels will be enforced in Canada. The Federal Government has introduced legislation aimed at reducing greenhouse gas emissions using an "intensity based" approach, the specifics of which have yet to be determined. Bill C 288, which is intended to ensure that Canada meets its global climate change obligations under the Kyoto Protocol, was passed by the House of Commons on February 14, 2007. On April 26, 2007, the Federal Government released its Action Plan to Reduce Greenhouse Gases and Air Pollution (the "Action Plan") also known as ecoACTION which includes the regulatory framework for air emissions. This Action Plan covers not only large industry, but regulates the fuel efficiency of vehicles and the strengthening of energy standards for a number of energy using products. The Government of Canada and the Province of Alberta released on January 31, 2008 the final report of the Canada-Alberta ecoENERGY Carbon Capture and Storage Task Force, which recommends among others: (i) incorporating carbon capture and storage into Canada's clean air regulations; (ii) allocating new funding into projects through competitive process; and (iii) targeting research to lower the cost of technology.

On March 10, 2008, the Government of Canada released "Turning the Corner – Taking Action to Fight Climate Change" (the "Updated Action Plan") which provides some additional guidance with respect to the Government of Canada's plan to reduce greenhouse gas emissions by 20% by 2020 and by 60% to 70% by 2050. The Updated Action Plan is primarily directed towards industrial emissions from certain specified industries including the oil sands, oil and gas and refining industries. The Updated Action Plan is intended to force industry to reduce greenhouse gas emissions and to create a carbon emissions trading market, including an offset system, to provide incentives to reduce greenhouse gas emission and establish a market price for carbon. The Updated Action Plan provides for: (i) mandatory reductions of 18% from the 2006 baseline starting in 2010 and by an additional 2% in subsequent years for existing facilities; (ii) new facilities built between 2004 and 2011 will have mandatory emissions standards based upon clean fuel standards (natural gas) with a 2% reduction below the third years intensity levels; and (iii) oil sands plants built in 2012 and later which use heavier hydrocarbons and upgraders and in situ production will have mandatory standards in 2018 based carbon capture and storage or other green technologies intensity. For the upstream oil and gas industry, the Updated Action Plan also provides for a company threshold of 10,000 boe/day and facility threshold of 3,000 tonnes of CO2.

Environmental legislation in the Province of Alberta has been consolidated into the Environmental Protection and Enhancement Act (Alberta) (the "EPEA") and the Oil and Gas Conservation Act (Alberta) (the "OGCA"). The EPEA and OGCA impose environmental standards, require compliance, reporting and monitoring obligations, and impose penalties. In 2006, the Alberta Government enacted regulations pursuant to the EPEA to specifically target sulphur oxide and nitrous oxide emissions from industrial operations including the oil and gas industry. In addition, the reduction emission guidelines outlined in the Climate Change and Emissions Management Amendment Act came into effect on July 1, 2007. Under this legislation, Alberta facilities emitting more than 100,000 tonnes of greenhouse gases a year must reduce their emissions intensity by 12%. Companies have three options to choose from in order to meet the reduction requirements outlined in this legislation, and these are: (i) by making improvement to

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operations that result in reductions; (ii) by purchasing emission credits from other sectors or facilities that have emissions below the 100,000 tonne threshold and are voluntarily reducing their emission; or (iii) by contributing to the Climate Change and Emissions Management Fund. Companies can either choose one of these options or a combination thereof. The Trust is committed to meeting its responsibilities to protect the environment wherever it operates and anticipates making increased expenditures of both a capital and an expense nature as a result of the increasingly stringent laws relating to the protection of the environment, and will be taking such steps as required to ensure compliance with the EPEA and similar legislation in other jurisdictions in which it operates. The Trust believes that it is reasonably likely that the trend towards stricter standards in environmental legislation and regulation will continue.

On January 24, 2008, the Alberta Government announced a new climate change action plan that will cut Alberta's projected 400 million tonnes of emissions in half by 2050. This plan is based on three areas: (i) carbon capture and storage; (ii) energy conservation and efficiency; and (iii) greening production through increased investment in clean energy technology, as well as the funding of projects that reduce the cost of separating CO2 from other emissions supporting carbon capture and storage.

Exports from Canada

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

RISK FACTORS

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

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

Oil and Gas Production Risk Factors

Exploitation and Development

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

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Operations

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

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

Oil and Natural Gas Prices

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

Marketing

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

Capital Investment

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

Reserves

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

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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. See "Information Concerning the Oil and Gas Industry - Environmental Regulation".

Delay in Cash Distributions

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

Reliance on Provident

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

Depletion of Reserves

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

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

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

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

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Write-downs of Oil and Gas Property Investments

Lower oil and gas prices increase the risk of write-downs of Provident’s oil and gas property investments. Under Canadian accounting rules, the net capitalized cost of oil and gas properties may not exceed a "ceiling limit" that is based, in part, upon estimated future net cash flows from reserves. If oil and natural gas prices decline, Provident’s net capitalized cost may exceed this cost ceiling, ultimately resulting in a charge against Provident’s earnings. Under U.S. GAAP, the cost ceiling is generally lower than under Canadian GAAP because the future net cash flows used in the United States ceiling test are discounted to a present value. Accordingly, Provident would have more risk of a ceiling test write-down in a declining price environment if it reported under U.S. GAAP. While these write-downs would not affect cash flow, the charge against earnings could be viewed unfavourably in the market.

Regulatory Matters

The oil and gas industry in Canada operates under federal, provincial and municipal legislation and regulation governing such matters as land tenure, prices, royalties, production rates, environmental protection controls, income, the exportation of crude oil, natural gas and other products, as well as other matters. The industry is also subject to regulation by governments in such matters as the awarding or acquisition of exploration and production rights or other interests, the imposition of specific drilling obligations, environmental protection controls, control over the development and abandonment of fields (including restrictions on production) and possibly expropriation or cancellation of contract rights.

Government regulations may be changed from time to time in response to economic or political conditions. The exercise of discretion by governmental authorities under existing regulations, the implementation of new regulations or the modification of existing regulations affecting the oil and gas industry could reduce demand for crude oil and natural gas, increase Provident’s costs and have a material adverse impact on Provident.

Before proceeding with a project the participants in the project must obtain all required regulatory approvals. The regulatory approval process can involve stakeholder consultation, environmental impact assessments and public hearings, among other things. In addition, regulatory approvals may be subject to conditions including security deposit obligations and other commitments. Failure to obtain regulatory approvals, or failure to obtain them on a timely basis, could result in delays and abandonment or restructuring of the projects undertaken by Provident and increased costs, all of which could have a material adverse affect on Provident.

Kyoto Protocol

Canada is a signatory to the United Nations Framework Convention on Climate Change and has ratified the Kyoto Protocol established thereunder to set legally binding targets to reduce nationwide emissions of carbon dioxide, methane and nitrous oxide greenhouse gases. Provident’s business and operations produce some of the greenhouse gases covered by the Convention. Future federal legislation, together with provincial emission reduction requirements, such as those proposed in Alberta’s Climate Change and Emissions Management Act, may require the reduction of emissions or emissions intensity from Provident’s business and operations. The reductions may not be technically or economically feasible and the failure to meet such emissions reduction requirements may materially adversely affect Provident’s business and result in fines, penalties and the suspension of operations. No assurance can be given that future environmental approvals, laws or regulations will not adversely impact the ability to operate Provident’s business or increase or maintain production or will not increase unit costs of production. Equipment from suppliers which can meet future emission standards may not be available on an economic basis and other methods of reducing emissions to required levels in the future may significantly increase operating costs or reduce output. There is a risk that the federal and/or provincial governments could pass legislation which would tax such emissions or require, directly or indirectly, reductions in such emissions produced by energy industry participants for which Provident may be unable to mitigate.

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Mitigation of the risk of future legislative or regulatory limits on the emission of greenhouse gases may include the acquisition of emission reduction or off set credits from third parties. However, emission reduction or off set credits may not be available for acquisition by Provident or may not be available on an economic basis and may not be recognized or qualify under future legislative or regulatory regimes as mitigation for the emission of greenhouse gases by Provident. See "Information Concerning Oil and Gas Industry - Environmental Regulation".

Royalties

Provident’s revenue and expenses are directly affected by the royalty regimes applicable to its oil and gas activities. The government of the Province of Alberta or of any other jurisdiction where Provident carries on business could adopt new royalty regimes which will make capital expenditures uneconomic and there can be no assurance that the regime currently in place will remain unchanged.

On October 25, 2007, the Government of Alberta unveiled a new royalty regime. The new regime will introduce new royalties for conventional oil, natural gas and bitumen effective January 1, 2009 that are linked to price and production levels and will apply to oil and gas activities.

The Trust's reserves and future net revenues associated thereto as incorporated by reference in this Annual Information Form do not reflect the increased royalties contemplated by the proposed new royalty regime and, after taking the new royalty regime into account, such values may be adversely affected.

Additionally, certain proposed changes contemplate further public and/or industry consultation. There may be modifications introduced to the proposed royalty structure prior to the implementation thereof. There are no assurances that the proposed royal regime will be implemented in the form proposed by the Government of Alberta. If changes are made to the proposed royalty regime before it is implemented, such changes could be more adverse to Provident than the royalty regime currently proposed. See "Information Concerning the Oil and Gas Industry - Provincial Royalties and Incentives".

Aboriginal Claims

Aboriginal people have claimed aboriginal title and rights to a substantial portion of western Canada. Provident is unable to assess the effect, if any, that any such claim would have on its business and operations.

Natural Gas Midstream, NGL Processing and Marketing Business Risk Factors

Facilities Throughput

The volumes of natural gas processed through Provident's natural gas midstream, NGL processing and marketing business and of NGLs and other products transported in the pipelines depend on production of natural gas in the areas serviced by the business and pipelines. Without reserve additions, production will decline over time as reserves are depleted and production costs may rise. Producers may shut in production at lower product prices or higher production costs. Producers in the areas serviced by the business may not be successful in exploring for and developing additional reserves, and the gas plants and the pipelines may not be able to maintain existing volumes of throughput. Commodity prices may not remain at a level which encourages producers to explore for and develop additional reserves or produce existing marginal reserves.

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

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

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

Operational Matters and Hazards

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

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

Operating and Capital Costs

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

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

Competition

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

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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.

Frac Spread

The Midstream NGL Business' exposure to commodity price risk applies mainly to frac spread. The Midstream NGL 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 Midstream NGL 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

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L.P. and AmeriGas Partners L.P. EnCana Corporation and its affiliates ("EnCana") will purchase the majority of the condensate from the EnCana Empress Debutanizer and will also be the principal supplier of natural gas and NGL for the Midstream NGL Business. BP Canada operates the BP E1 Plant at Empress, Alberta and the west to east system described herein. If for any reason these parties were unable to perform their obligations under the various agreements with Provident, the revenue and distributions of the Trust, and the operations of the Midstream NGL Business could be negatively impacted.

General Risk Factors

Risks Associated With the Level of Foreign Ownership

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

There would be material adverse tax consequences if the Trust lost its status as a mutual fund trust under Canadian tax laws

It is intended that the Trust continue to qualify as a mutual fund trust for purposes of the Tax Act. The Trust may not, however, always be able to satisfy any future requirements for the maintenance of mutual fund trust status. Should the status of the Trust as a mutual fund trust be lost or successfully challenged by a relevant tax authority, certain adverse consequences may arise for the Trust and Unitholders. Some of the significant consequences of the Trust losing mutual fund trust status are as follows:

·	The Trust would be taxed on certain types of income distributed to Unitholders. Payment of this tax may have adverse consequences for some Unitholders, particularly Unitholders that are not residents of Canada and residents of Canada that are otherwise exempt from Canadian income tax.

·	Trust Units held by Unitholders that are not residents of Canada would become taxable Canadian property. These non-resident holders would be subject to Canadian income tax on any gains realized on a disposition of Trust Units held by them.

The Trust may take certain measures in the future to the extent the Trust believes them necessary to ensure that it maintains its status as a mutual fund trust. These measures could be adverse to certain holders of Trust Units.

Availability of Credit and Debt Service

As of March 19, 2008, the Trust had drawn $908.0 million against the Canadian credit facility and had $29.6 million of the Canadian credit facility drawn on letters of credit, representing 83 percent of the Canadian credit capacity. In addition, as of March 19, 2008, the Trust had drawn US$382.0 million against the U.S. credit facility and had US$4.3 million of the U.S. credit facility drawn on letters of credit, representing 53 percent of the U.S. credit capacity. Variations in interest rates and scheduled principal repayments or the need to refinance the credit facility upon expiration could result in significant changes in the amount required to be applied to debt service before payment of any amounts to the Trust.

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Although it is believed that the credit facilities are sufficient, there can be no assurance that the amounts will be adequate for the financial obligations of the Trust, that additional funds can be obtained or that, upon expiration, the credit facility can be refinanced on terms acceptable to the Trust or the lenders. In such circumstances, cash distributions may be reduced.

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

Changes in Legislation

There is no assurance that Canadian federal income tax laws, including the treatment of mutual fund trusts thereunder, will not be changed in a manner that affects Unitholders in a material adverse way. See "Information Concerning the Trust, Provident and Certain Subsidiaries - Provident Energy Trust - Taxation of the Trust".

Nature of Trust Units

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

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

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

Redemption Right

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

Unitholder Limited Liability

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

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

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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.

INTERESTS OF MANAGEMENT AND OTHERS IN MATERIAL TRANSACTIONS

No director or executive officer of Provident, no person or company that beneficially owns, or controls or directs, directly or indirectly, more than 10 percent of the outstanding Trust Units and no associate or affiliate of any of the foregoing persons or companies, has or has had any material interest, direct or indirect, in any transaction within the three most recently completed financial years or during the current financial year that has materially affected or is reasonably expected to materially affect the Trust, other than as described in this Annual Information Form.

TRANSFER AGENT AND REGISTRAR

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

INTERESTS OF EXPERTS

As of the date hereof, the designated professionals of McDaniel, independent oil and gas reservoir engineers, as a group, beneficially own, directly or indirectly, less than 1 percent of the Trust Units. As of the date hereof, the designated professionals of NSAI, independent oil and gas reservoir engineers, as a group, do not beneficially own, directly or indirectly, any Trust Units. As of the date hereof, the designated professionals of AJM, independent oil and gas reservoir engineers, as a group, beneficially own, directly or indirectly, less than 1 percent of the Trust Units. As of the date hereof, the designated professionals of Schlumberger, independent oil and gas reservoir engineers, as a group, beneficially own, directly or indirectly, less than 1 percent of the Trust Units.

MATERIAL CONTRACTS

There are no material contracts entered into by the Trust or its subsidiaries during the most recently completed financial year or since January 1, 2002 and which are still in effect, other than contracts entered into in the ordinary course of business and other than (a) the Trust Indenture described herein under the heading "Information Concerning the Trust, Provident and Certain Subsidiaries"; and (b) the Canadian Credit Facility described herein under the heading "Information Concerning the Trust, Provident and Certain Subsidiaries - Debt Financing".

Each of the Trust Indenture and the Canadian Credit Facility has been filed on SEDAR and is available under the Trust's issuer profile at www.sedar.com.

DOCUMENTS INCORPORATED BY REFERENCE

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

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

The Trust will provide without charge to each security holder to whom this Annual Information Form is delivered, upon the written or oral request of such person (and to each person who is not a security holder of the Trust upon payment of a reasonable charge), a copy of any or all of the documents incorporated herein by reference, other than exhibits to such documents (unless such exhibits are specifically incorporated by reference into such documents). Requests for such documents should be directed to the office of Investor Relations, Provident Energy Ltd., 2100, 250 - 2nd Street S.W., Calgary, Alberta T2P 0C1, telephone: (403) 296-2233. Documents incorporated by reference in this Annual Information Form are also available on SEDAR at www.sedar.com.

PRINCIPAL HOLDERS OF TRUST UNITS

As at the date hereof, to the knowledge of Provident, no person or company owned of record or beneficially, directly or indirectly, more than 10 percent of the issued and outstanding Trust Units. As at March 19, 2008, the directors and senior officers of Provident, as a group, beneficially owned, directly or indirectly, 2.3 million Trust Units or approximately 1 percent of the issued and outstanding Trust Units.

ADDITIONAL INFORMATION

Additional information related to the remuneration of the directors and officers of Provident for the year ended December 31, 2007, the indebtedness of the directors and officers of Provident, the principal holders of Trust Units and securities authorized for issuance under equity compensation plans, where applicable, is contained in the Management Proxy Statement and Information Circular of the Trust dated March 27, 2008, which relates to the Annual and Special Meeting of the Unitholders to be held on May 8, 2008. Additional financial information is provided in the Trust's audited consolidated financial statements and management's discussion and analysis for the year ended December 31, 2007.

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

Lynn Rannelli, Assistant Corporate Secretary

Provident Energy Ltd.

2100, 250 – 2nd Street S.W.

Calgary, Alberta T2P 0C1

Telephone:	(403) 296-2233
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:

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

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

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

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

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

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

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

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

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

Responsibilities

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

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

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

Specific Duties

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

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

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

(d)

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

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

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

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

(iii)

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

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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

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

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

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

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

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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.

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

October/November Meeting

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

audit team and potential rotation;

review and consideration of budgeted audit fees; and

special areas for concentration by external audit.

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

·	Review Audit Committee charter and report to Board.

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

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

· Educational component to Audit Committee functions such as:

critical accounting policies/estimates/general discussion;

treasury activities;

internal control risks;

support to CEO/CFO certification;

financing vehicles, loan documents and applicable covenant patterns;

taxation issues and tax planning;

new developments such as:

- non-GAAP earnings measures; and

- identification of financial experts;

competitors and accounting issues involving competitors;

preparing of Audit Committee effectiveness report for Board of Directors;

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

earnings guides such as:

- pro forma reporting; and

- selective disclosure policy.

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

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

·	Review of complaints received and outcome of investigation.

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

The following analysis provides a detailed explanation of Provident’s operating results for the year ended December 31, 2007 compared to the year ended December 31, 2006 and should be read in conjunction with the consolidated financial statements of Provident. This analysis has been prepared using information available up to March 18, 2008.

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

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

This analysis contains forward-looking information and statements. See “Forward-looking statements” at the end of the analysis for further discussion.

Consolidated funds flow from operations and cash distributions
Consolidated				Year ended December 31,
($ 000s, except per unit data)	2007			2006			% Change

Revenue, Funds Flow from Operations and Distributions
Revenue (net of royalties and financial derivative instruments)	$	2,167,276		$	2,187,253			(1	)
Funds flow from operations	$	468,255		$	432,664			8
Per weighted average unit - basic and diluted (1)	$	2.04		$	2.20			(7	)
Declared distributions	$	333,352		$	283,465			18
Per Unit		1.44			1.44			-
Percent of funds flow from operations distributed (2)		77	%		67	%		15

(1)	Includes dilutive impact of unit options, exchangeable shares and convertible debentures.

(2)	Calculated as declared distributions to unitholders divided by funds flow from operations less distributions to non-controlling interests of $35.8 million (2006 - $6.5 million).

Management uses funds flow from operations to analyze operating performance. Funds flow from operations represents cash flow from operations before changes in working capital and site restoration expenditures. Provident also reviews funds flow from operations in setting monthly distributions and takes into account cash required for debt repayment and/or capital programs in establishing the amount to be distributed.

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

For the year ended December 31, 2007, funds flow from operations increased eight percent or $35.6 million to $468.3 million from $432.7 million for 2006 (per unit in 2007 - $2.04; 2006 - $2.20) . COGP generated $204.3 million, USOGP $85.6 million, and Midstream $178.4 million of funds flow from operations during 2007. During 2006 COGP generated funds flow from operations of $185.3 million, USOGP $63.0 million, and Midstream $184.4 million.

Canadian oil and gas operations contributed funds flow from operations of $204.3 million in 2007, an increase of $19.0 million or 10 percent when compared with $185.3 million from 2006. The 2007 results reflect higher production from the acquisitions of Capitol Energy Resources Ltd. (“Capitol”) on June 19, 2007 and Triwest Energy Inc. (“Triwest”) on December 3, 2007, which are primarily light/medium crude oil production and a full year of production from the natural gas-weighted Rainbow assets acquired on August 31, 2006. In addition, incremental production from capital drilling programs in the core areas and higher realized crude oil and natural gas liquids prices contributed to the increase in funds flow from operations. These factors were offset by natural production declines, a lower realized natural gas price tied to the lower AECO natural gas index price, and reduced realized gains on financial derivative instruments compared to 2006.

The Midstream business unit added $178.4 million to 2007 funds flow from operations, compared with $184.4 million recorded in the year ended December 31, 2006. Midstream funds flow from operations reflects higher operating margins for all three business lines within the Midstream segment, offset by realized losses on financial derivative instruments, foreign exchange losses and higher interest costs due to increased corporate long-term debt balances.

The U.S. oil and gas operations provided increased funds flow from operations of $85.6 million in 2007, compared to $63.0 million in 2006, primarily driven by increased production due to oil and gas property acquisitions by the MLP in 2007, including the $1.5 billion USOGP natural gas asset acquisition in November 2007, partially offset by the impact of $13.9 million (2006 -$4.9 million) in cash payments, primarily in the first quarter of 2007, for unit based compensation related to the 2006 fiscal year. The expense was recorded as non-cash unit based compensation in 2006 and resulted in a decrease to funds flow from operations when paid in 2007.

Declared distributions in 2007 totaled $333.4 million, 77 percent of funds flow from operations, after distributions to non-controlling interests of $35.8 million. This compares to $283.5 million of declared distributions in 2006, 67 percent of funds flow from operations, after distributions to non-controlling interests of $6.5 million. In previous years, Provident has paid out between 67 percent and 102 percent of its annual funds flow from operations as distributions to unitholders.

Outlook

Provident’s upstream and midstream operations are on track for 2008, as the Trust continues to focus on operational excellence to deliver on our base capital plan and realize additional upside through additional opportunities available in our asset base.

In the Canadian upstream business, the two acquisitions in 2007 (Capitol Energy and Triwest), the Rainbow acquisition in 2006, and Provident’s existing assets provide Provident with approximately 1,000 identified drilling and recompletion opportunities. The program is well underway to drill 92 net wells in 2008, and to undertake a further 74 recompletions and workovers, with a total $134 million capital budget. Provident expects Canadian upstream production to average approximately 26,000 to 28,000 barrels of oil equivalent per day (boed) in 2008. Provident expects drilling and operating costs to ease somewhat in 2008, as activity in the sector levels off and we realize the benefit of the high quality assets acquired.

The U.S. upstream business anticipates a 2008 capital program of approximately U.S.$158 million with average production expected to be in the range of 20,900 to 22,800 boed (net of royalties). BreitBurn Energy Partners, L.P. (the “MLP”) has a capital budget of approximately U.S.$120 million and plans to drill 206 net wells in 2008. MLP production is expected to be in the range of 18,300 to 20,000 boed (net of royalties) in 2008. BreitBurn Energy Company LP (“BreitBurn”) has a capital budget of up to U.S.$38 million with plans to drill 12 net wells in 2008. BreitBurn production is expected to be in the range of 2,600 to 2,800 boed (net of royalties) in 2008.

Provident anticipates a capital program of $43 million for the Midstream business in 2008. Management anticipates that approximately $18 million will be invested in ongoing development of new underground storage caverns at Redwater, and $10 million will go toward further rail yard development. The 2008 sustaining capital budget has been raised to $13 million, and includes planned expenditures on operated and non-operated facilities. Assuming continued strong market conditions, Provident anticipates another successful year in 2008 for the Midstream business.

On February 5, 2008, Provident announced a strategic sales process of its U.S. oil and gas operations. Currently Provident owns approximately 22 percent of the MLP, including units held by the General Partner of which Provident indirectly owns approximately 96 percent. Provident also owns, through a wholly owned subsidiary, approximately 96 percent of BreitBurn. The book value of these investments at December 31, 2007 was approximately $425 million and the related tax basis is estimated to be approximately $100 million. It is Provident’s intention to monetize its U.S. upstream investment, but there is no certainty that this process will result in any changes to Provident’s ownership stakes in its U.S. holdings.

Strategic planning in 2008 will continue to focus on a review of Provident’s Canadian businesses and initiatives to consider the most viable strategic and structural options available with the objectives of capturing and protecting unitholder value going forward. Certain options under consideration include the separation of the upstream and the midstream components of Provident’s Canadian business. Provident cautions that the planning required before implementation will be lengthy and complex. There is no certainty that the planning will result in significant changes in Provident.

Distributions

The following table summarizes distributions paid as declared by the Trust since inception:
		Distribution Amount
Record Date	Payment Date	(Cdn$)		(US$)*
2007
January 22, 2007	February 15, 2007	$	0.12		0.10
February 28, 2007	March 15, 2007		0.12		0.10
March 22, 2007	April 13, 2007		0.12		0.11
April 24, 2007	May 15, 2007		0.12		0.11
May 18, 2007	June 15, 2007		0.12		0.11
June 22, 2007	July 13, 2007		0.12		0.11
July 23, 2007	August 15, 2007		0.12		0.11
August 22, 2007	September 14, 2007		0.12		0.12
September 24, 2007	October 15, 2007		0.12		0.12
October 22, 2007	November 15, 2007		0.12		0.12
November 21, 2007	December 14, 2007		0.12		0.12
December 21, 2007	January 15, 2008		0.12		0.12
2007 Cash Distributions paid as declared		$	1.44		1.35
2006 Cash Distributions paid as declared			1.44		1.26
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, 2007 – Distributions paid as declared		$	12.39		9.31

*Exchange rate based on the Bank of Canada noon rate on the payment date. The increase in distributions in U.S. dollars in 2007 is due to the increase in the Canadian dollar relative to the U.S. dollar.

For Canadian tax purposes, 2007 distributions were determined to be 94.8 percent taxable and 5.2 percent tax-deferred return of capital in the hands of Canadian unitholders. The 2006 comparables were 93.2 percent and 6.8 percent, respectively. Distributions received by U.S. resident unitholders in 2007 were classified as 97.6 percent qualified dividend and 2.4 percent tax deferred return of capital. The 2006 comparables were 97.7 percent and 2.3 percent respectively. In both Canada and the U.S., the tax-deferred portion would usually be treated as an adjustment to the cost base of the units. Unitholders or potential unitholders should consult their own legal or tax advisors as to their particular income tax consequences of holding Provident units.

Taxation of trust income

In 2007, future income tax expense includes $88.4 million relating to the enactment of Bill C-52, Budget Implementation Act 2007 by the Canadian government. This bill contains legislation to tax publicly traded trusts including Provident. The new legislation limits the tax deductibility of cash distributions after 2010 such that income taxes may become payable in the future. As a result of this legislation, the Trust is now required to record the future tax effect of the temporary differences on its flow through entities that are expected to reverse subsequent to 2010.

The Trust has estimated its future income taxes based on estimates of results of operations and tax pool claims and cash distributions in the future assuming no material change to the Trust’s current organizational structure. The Trust’s estimate of future income taxes does not incorporate any assumptions related to a change in organizational structure until such structures are given legal effect.

The Trust’s estimate of its future income taxes will vary as do the Trust’s assumptions pertaining to the factors described above, and such variations may be material.

The new legislation will not affect the Trust’s cash flows from operations and accordingly the Trust’s financial condition until 2011, based on our planned compliance with the legislated growth guidelines.

The Trust has approximately $1.5 billion in tax pools available to claim against taxable income (see “Taxes”). Provident plans to manage discretionary tax pool claims to defer payment of current taxes as long as possible. Provident has made estimates of taxability in future years based on a number of assumptions including: future product prices; future production and sales; future operating and product costs; future general and administrative costs; future capital expenditures; and general business conditions. Using these assumptions about future events which may or may not occur, Provident estimates that:

current taxes on Canadian oil and gas operations would occur after 2016; and
current taxes for midstream operations would occur in 2011.

Net income

Consolidated			Year ended December 31,
($ 000s, except per unit data)	2007		2006		% Change
Net income	$	30,434	$	140,920		(78	)
Per weighted average unit
– basic and diluted (1)	$	0.13	$	0.72		(82	)

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

Consolidated				Year ended December 31,
($ 000s)	2007			2006		% Change
COGP net income	$	45,065		$	83,453		(46	)
USOGP net income		146,389			2,598		5,535
Total oil and gas net income	$	191,454		$	86,051		122
Midstream net (loss) income		(161,020	)		54,869		-
Consolidated net income	$	30,434		$	140,920		(78	)

Net income for the year ended December 31, 2007 decreased to $30.4 million compared to $140.9 million of net income in the comparable 2006 period. On a consolidated basis, favorable operating results were more than offset by a $281.0 million change in unrealized loss on financial derivative instruments and increased depletion, depreciation and accretion (DD&A) expense.

The COGP business segment’s net income was $45.0 million, a $38.4 million reduction compared with the year ended December 31, 2006 net income of $83.4 million. An increase in EBITDA was more than offset by unrealized losses on financial derivative instruments and increased DD&A resulting from the acquisitions of Capitol and Triwest in 2007, and the Rainbow assets in 2006.

The Midstream segment recorded a net loss of $161.0 million as compared to net income of $54.9 million in the year ended December 31, 2006. The loss was primarily attributable to the impact of the commodity price risk management program. In 2007, Midstream generated a $76.9 million or 30 percent increase in gross operating margin, reflecting the positive price environment. Offsetting this was a $59.1 million increase in realized losses on financial derivative instruments and $192.9 million in unrealized losses on financial derivative instruments in 2007 representing a $124.6 million increase from 2006. Additionally, the Midstream segment recognized future income tax expense of $94.2 million, an increase of $92.7 million from 2006, primarily due to the enactment in 2007 of legislation to tax publicly traded trusts in 2011.

For the year ended December 31, 2007, USOGP net income was $146.4 million as compared to $2.6 million in the year ended December 31, 2006. USOGP net income in 2007 includes a dilution gain of $260.3 million recognized at the time MLP units were issued to third parties to finance growth (see note 9 to consolidated financial statements). In addition, EBITDA increased by $19.9 million, or 26 percent, primarily due to the USOGP natural gas asset acquisition in the fourth quarter of 2007. Partially offsetting these factors was unrealized losses on financial derivative instruments of $110.0 million in 2007 compared to unrealized gains of $7.7 million in 2006.

The significant swing in Provident’s net income year-over-year illustrates the extent to which net income figures are impacted by the requirement to “mark to market” all unrealized gains and losses associated with financial derivative instruments at a point in time and report these against current period income. Because Provident’s commodity price risk management program extends up to five years into the future in the Midstream segment, net earnings can show substantial variation that is not necessarily related to current operations.

Reconciliation of non-GAAP measure

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

EBITDA Reconciliation				Year ended December 31,
($ 000s)	2007			2006			% Change
EBITDA	$	545,096		$	495,889			10
Adjusted for:
Cash interest		(69,565	)		(55,891	)		24
Unrealized loss on financial derivative instruments		(324,284	)		(43,314	)		649
Dilution gain		260,324			-			-
Depletion, depreciation and accretion and
other non-cash expenses		(376,192	)		(279,188	)		35
Income before taxes and non-controlling interests	$	35,379		$	117,496			(70	)

Reconciliation of funds flow from operations to distributions				Year ended December 31,
($ 000's, except per unit amounts)	2007			2006			% Change
Cash provided by operating activities	$	464,455		$	414,349			12
Change in non-cash operating working capital		(624	)		13,693			-
Site restoration expenditures		4,424			4,622			(4	)
Funds flow from operations		468,255			432,664			8
Distributions to non-controlling interests		(35,846	)		(6,523	)		450
Cash retained for financing and investing activities		(99,057	)		(142,676	)		(31	)
Distributions to unitholders		333,352			283,465			18
Accumulated cash distributions, beginning of period		926,825			643,360			44
Accumulated cash distributions, end of period	$	1,260,177		$	926,825			36
Cash distributions per unit	$	1.44		$	1.44			-

Proportionate disclosures

Included in the consolidated financial results of Provident, and the USOGP segment in particular, are the consolidated results of the MLP and BreitBurn. At December 31, 2007 Provident owned approximately 22 percent of the MLP and 96 percent of BreitBurn. In accordance with generally accepted accounting principles in Canada and the United States, these investments are consolidated into Provident’s results, with 100 percent of assets, liabilities, revenues and expenses recorded along with a corresponding non-controlling interest. In other sections of Management’s Discussion and Analysis, information is presented in its consolidated form to correspond with the consolidated financial statements of Provident. This section presents a number of metrics that reflect Provident’s proportionate interest in these investments.

Management uses proportionate information to analyze operating performance. The proportionate information as presented does not have any standardized meaning prescribed by Canadian GAAP and therefore may not be comparable with the calculation of similar measures for other entities. The proportionate information as presented is not intended to be viewed as an alternative to the corresponding measures of financial performance calculated in accordance with Canadian GAAP.

	Year ended December 31,
Oil and gas production (boed)	2007			2006
COGP		26,509			24,018
USOGP (1)
MLP (total)		9,518			1,279
Less: Non-controlling interest		(5,454	)		(434	)
Provident's interest		4,064			845
BreitBurn (total)		2,606			6,442
Less: Non-controlling interest		(112	)		(287	)
Provident's interest		2,494			6,155
Total USOGP - Provident's interest		6,558			7,000
Total - Provident's interest		33,067			31,018

(1)	In the fourth quarter of 2006, approximately two-thirds of USOGP production and approximately one-half of USOGP reserves were transferred from BreitBurn to the MLP as part of the initial public offering of the MLP.

	Year ended December 31,
Funds flow from operations ($ 000's)	2007			2006
COGP	$	204,252		$	185,328
Midstream		178,432			184,366
USOGP (1)
MLP (total)		85,609			12,017
Less: Non-controlling interest		(49,118	)		(4,068	)
Provident's interest		36,491			7,949
BreitBurn (total)		10,821			63,555
Less: Non-controlling interest		(438	)		(2,828	)
Provident's interest		10,383			60,727
Other USOGP (corporate allocations)		(10,859	)		(12,602	)
Total USOGP - Provident's interest		36,015			56,074
Total - Provident's interest	$	418,699		$	425,768

(1)	In the fourth quarter of 2006, approximately two-thirds of USOGP production and approximately one-half of USOGP reserves were transferred from BreitBurn to the MLP as part of the initial public offering of the MLP.

	Year ended December 31,
Capital expenditures ($ 000's)	2007			2006
COGP	$	146,209		$	70,088
Midstream		31,904			66,008
USOGP (1)
MLP (total)		27,936			2,604
Less: Non-controlling interest		(15,392	)		(883	)
Provident's interest		12,544			1,721
BreitBurn and other (total)		41,073			51,733
Less: Non-controlling interest		(1,769	)		(2,302	)
Provident's interest		39,304			49,431
Total USOGP - Provident's interest		51,848			51,152
Total - Provident's interest	$	229,961		$	187,248

(1)	In the fourth quarter of 2006, approximately two-thirds of USOGP production and approximately one-half of USOGP reserves were transferred from BreitBurn to the MLP as part of the initial public offering of the MLP.

	As at December 31,
Long-term debt - revolving term credit facilities ($ 000's)	2007			2006
COGP (1)	$	230,999		$	172,980
Midstream (1)		692,997			518,941
USOGP (2)
MLP (total)		359,712			1,749
Less: Non-controlling interest		(280,627	)		(593	)
Provident's interest		79,085			1,156
BreitBurn (total)		9,124			9,323
Less: Non-controlling interest		(363	)		(415	)
Provident's interest		8,761			8,908
Total USOGP - Provident's interest		87,846			10,064
Total - Provident's interest	$	1,011,842		$	701,985

(1)	Provident's credit facilities have been allocated for reporting purposes as 25 percent COGP and 75 percent Midstream.

(2)	In the fourth quarter of 2006, approximately two-thirds of USOGP production and approximately one-half of USOGP reserves were transferred from BreitBurn to the MLP as part of the initial public offering of the MLP.

Taxes

Consolidated			Year ended December 31,
($ 000s)	2007		2006			% Change
Capital tax expense	$	3,762	$	1,314			186
Current and withholding tax expense		6,362		5,829			9
Future income tax expense (recovery)		30,487		(34,316	)		-
	$	40,611	$	(27,173	)		-

Capital taxes in 2007 totaled $3.8 million, an increase from the $1.3 million expense recorded in 2006. The increase is due to greater production subject to the Saskatchewan resource surcharge.

The current and withholding tax expense of $6.4 million in 2007 compares to $5.8 million in 2006. The majority of these taxes arise from Provident’s U.S.-based operations. The increase in current taxes was due to U.S.-based Midstream operations. For the year ended December 31, 2007, future income tax expense was $30.5 million, compared with a recovery of $34.3 million in 2006. The 2007 expense includes $88.4 million relating to the second quarter enactment of legislation to tax publicly traded trusts in 2011.

For the year ended December 31, 2007, the total income tax expense was $40.6 million. Based on 2007 income before taxes of $71.0 million, the expected income tax expense was $23.3 million. The main reason for the larger than expected income tax expense is $88.4 million of future income taxes recorded as a result of the enactment of legislation to tax publicly traded trusts in 2011 (see “Taxation of trust income”). The offsetting difference between the expected expense and the total tax expense is primarily a result of deductions allowed when computing taxable income of the Trust for distributions made to unitholders. The Trust is a taxable entity under Canadian income tax law and is currently taxable only on income that is not distributed or distributable to the unitholders. If the Trust distributes all of its taxable income to the unitholders, no current provision for taxes is required by the Trust until 2011. Since inception, the Trust has distributed all of its taxable income to the unitholders. Additionally, interest and royalties are charged by the Trust to its subsidiaries, which are deductible in the computation of taxable income at the incorporated subsidiary level reducing tax pool claims in certain subsidiaries and potentially creating tax loss carry-forwards that result in future income tax recoveries.

Provident’s tax pools available to shelter future income as at December 31, 2007 are estimated as follows:

As at December 31, 2007
($ 000s)	COGP		USOGP(1)		Midstream		Total
Intangibles	$	560,000	$	90,000	$	-	$	650,000
Tangibles		290,000		65,000		280,000		635,000
Non-capital losses		165,000		-		20,000		185,000
	$	1,015,000	$	155,000	$	300,000	$	1,470,000
(1) Non-Canadian tax pools

Provident also has capital losses of approximately $435 million which are available to reduce the tax effect of future capital gains.

Interest expense

Consolidated				Year ended December 31,
($ 000s, except as noted)	2007			2006			% Change

Interest on bank debt	$	49,365		$	34,666			42
Weighted-average interest rate on bank debt		5.65	%		5.30	%		7
Interest on 8.75% convertible debentures		2,043			2,573			(21	)
Interest on 8.0% convertible debentures		1,974			2,500			(21	)
Interest on 6.5% convertible debentures		6,436			6,437			-
Interest on 6.5% convertible debentures		9,747			9,715			-
Total cash interest	$	69,565		$	55,891			24

Weighted average interest rate on all long-term debt		5.94	%		5.81	%		2

Debenture accretion and other non-cash interest expense		7,442			6,548			14
Total interest expense	$	77,007		$	62,439			23

Interest on bank debt increased in 2007 compared to 2006 due to increased capitalization including debt levels that resulted from the Capitol acquisition in the second quarter of 2007, the Rainbow asset acquisition in the third quarter of 2006 and the USOGP natural gas asset acquisition in the fourth quarter of 2007.

Financial instruments

Commodity price risk management program

For the year ended December 31, 2007 $80.7 million was recorded as a realized loss on financial derivative instruments due to the Commodity Price Risk Management Program (the Program) with $8.0 million related to the combined oil and gas operations and $79.0 million associated with the Midstream segment. In addition, $6.3 million was recorded as a realized gain related to settle foreign exchange based contracts.

In the oil and gas business units the realized loss in 2007 associated with crude oil totaled $17.6 million ($2.32 per barrel) and a realized gain of $9.6 million related to natural gas ($0.25 per gj). The combined total was a loss of $8.0 million or $0.57 per boe. In 2006 the Program recorded a realized gain of $1.9 million or $0.16 per boe with a realized loss of $5.7 million related to crude oil ($0.97 per barrel) and a realized gain of $7.6 million related to natural gas ($0.25 per gj).

In 2007 the Midstream segment recorded a realized loss of $79.0 million for NGL inventory price stabilization and frac-spread margin activities. In 2006 the Program recorded a realized loss of $15.4 million for these activities.

Realized gains on foreign exchange contracts related to the Program were $6.3 million. In 2006, the Program recorded a realized gain of $0.4 million for these activities.

On a per trust unit basis the opportunity cost of the Program increased to $0.35 per trust unit in 2007 from $0.07 per trust unit in 2006.

At December 31, 2007 the mark to market value of open contracts was in a net loss position of $378.0 million based upon commodity prices prevailing at that date. Under generally accepted accounting principles, these unrealized “mark-to-market” opportunity costs, which relate to financial derivative positions with effective periods ranging from 2008 through January 2013, are required to be recognized in the financial statements of Provident, affecting current period net income. These unrealized opportunity costs relate to financial derivative instruments which were entered into in order to manage commodity prices and protect future Midstream product margins. Fluctuations in the market value of these instruments have no impact on cash flow until the instruments are settled.

Provident’s commodity price risk management program includes a consistent, active and disciplined hedging program that utilizes derivative instruments to provide for insurance against lower commodity prices and margins. The program provides support for stable cash distributions, capital programs and bank financing. The hedging strategy protects a percentage of Provident’s oil and natural gas production against a decline in commodity prices while, with some products, allowing the Trust to participate in a rising commodity price environment. It provides price stabilization and protection of a percentage of inventory values and fractionation spread margin associated with the midstream services and marketing business unit. As well, the Provident hedging strategy reduces foreign exchange risk due to the exposure arising from the conversion of U.S. dollars into Canadian dollars.

Provident will continue to execute the program in 2008. The derivative instruments the Trust uses include puts, calls, costless collars, participating swaps, and fixed price products that settle against indexed referenced pricing.

Disclosure Controls and Procedures: U.S. Sarbanes-Oxley Act

In 2002, the United States Congress enacted the Sarbanes-Oxley Act (SOX), which stipulates that corporations publicly traded on U.S. financial exchanges must assess the effectiveness of their internal controls over financial reporting. As a foreign filer listed on the New York Stock Exchange, Provident is required to conduct the assessment. See “Management’s Report on Internal Control Over Financial Reporting” and “Independent Auditors’ Report”.

Based on their evaluation as of December 31, 2007, Provident’s chief executive officer and chief financial officer concluded that Provident’s disclosure controls and procedures (as defined in Rules 13(a)-15(e) and 15(d)-15(e) under the United States Securities Exchange Act of 1934 (the Exchange Act) are effective to ensure that information required to be disclosed by Provident in reports that it files or submits under the Exchange Act is recorded, processed, summarized and reported within the time periods specified in the United States Securities and Exchange Commission rules and forms. In addition, as of December 31, 2007, there were no changes in Provident’s internal controls over financial reporting that occurred during 2007 that have materially affected, or are reasonably likely to materially affect its internal controls over financial reporting.

Provident will continue to periodically evaluate its disclosure controls and procedures and internal controls over financial reporting and will make any modifications from time to time as deemed necessary.

The Trust has undertaken a comprehensive review of the effectiveness of its internal control over financial reporting as part of the reporting, certification and attestation requirements of Section 404 of the U.S. Sarbanes-Oxley Act of 2002. For the year ended December 31, 2007, the company’s internal controls were found to be operating free of any material weaknesses.

Acquisitions

In May 2007, BreitBurn Energy Partners L.P. (the “MLP”) completed two oil and gas property acquisitions, one in Florida for cash consideration of USD $108.1 million and one in California for cash consideration of USD $92.5 million. The acquisitions were financed by the issue of units by the MLP to institutional investors. As a result of these unit issues, Provident’s interest in the MLP decreased from approximately 66 percent to approximately 50 percent.

On June 19, 2007, Provident acquired Capitol Energy Resources Ltd. (“Capitol”) for cash consideration of $467.5 million. Capitol, a public oil and gas exploration and production company active in the Western Canadian sedimentary basin, had as its principal asset a long-life resource play at Dixonville, Alberta. This play is being exploited using horizontal wells and will be further developed using waterflood technology. The acquisition was financed by the issuance of 29,313,727 trust units at $12.75 per unit and Provident’s credit facility.

On November 1, 2007, the MLP acquired approximately $1.5 billion of natural gas, crude oil and related assets in Michigan, Indiana and Kentucky from Quicksilver Resources Inc. for U.S. $750 million in cash and approximately 21.3 million common units of the MLP. The acquisition is comprised of natural gas-weighted producing assets located primarily in the Michigan Antrim Shale. The cash portion of the purchase price was funded by a private placement of new MLP units and bank debt. As a result of this transaction, Provident’s interest in the MLP has decreased from approximately 50 percent to approximately 22 percent. Provident continues to control the MLP through its 95.6 percent ownership of the general partner, resulting in consolidation of the MLP in accordance with generally accepted accounting principles in Canada and the United States.

On December 3, 2007, the Trust acquired Triwest Energy Inc. (Triwest), a privately held company with oil assets in southeast Saskatchewan. The Trust issued 6.3 million trust units (at an ascribed value of $76.6 million) and paid $2.3 million in cash as consideration for the acquisition. Triwest provides the Trust with approximately 1,300 barrels per day of oil production.

Goodwill

Goodwill represents the excess of the cost of an acquired enterprise over the net of the amounts assigned to assets acquired and liabilities assumed. The Capitol Energy acquisition in the second quarter of 2007 resulted in additional goodwill of $86.0 million. In 2005, the Midstream NGL Acquisition resulted in goodwill of $100.4 million. Goodwill of $330.9 million arose from COGP acquisitions in 2002 and 2004.

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

Liquidity and capital resources

Consolidated				Year ended December 31,
($ 000s)	2007			2006			% Change

Long-term debt - revolving term credit facility	$	1,292,832		$	702,993			84
Long-term debt - convertible debentures		256,440			285,792			(10	)
Total debt		1,549,272			988,785			57

Equity (at book value)		1,708,665			1,542,974			11
Total capitalization at book value	$	3,257,937		$	2,531,759			29

Total debt as a percentage of total book value capitalization		48	%		39	%		23

Provident operates three business units with similar but not identical monthly cash settlement cycles. Midstream revenues are received at various times throughout the month. Provident’s working capital position is affected by seasonal fluctuations that reflect commodity price changes, drilling cycles in its oil and gas operations and inventory balances in its Midstream business unit. Provident relies on funds flow from operations, external lines of credit and access to equity markets to fund capital programs and acquisitions.

As at December 31, 2007, Provident held non-bank sponsored asset-backed commercial paper with a face value of $6.5 million. These securities were previously classified as a component of cash and cash equivalents on the balance sheet. Provident has recorded an impairment write-down amounting to $1.8 million to reflect the fair value of these assets at December 31, 2007. The write-down is included in net income as part of foreign exchange loss and other. As at December 31, 2007 these securities have been classified on the balance sheet as other current assets ($1.1 million) and investments ($3.6 million) due to a reduction in market liquidity for these investments. The resolution of the liquidity issues will not have a significant impact on Provident’s operations.

Contractual obligations
Consolidated			Payment due by period
			Less						More
			than 1		1 to 3		4 to 5		than 5
($ millions)	Total		year		years		years		years
Long-term debt - revolving term credit facilities (1)	$	1,483.4	$	76.1	$	1,407.3	$	-	$	-
Long-term debt - convertible debentures		343.0		39.1		58.0		245.9		-
Operating lease obligations		224.7		20.4		39.6		34.4		130.3
Total	$	2,051.1	$	135.6	$	1,504.9	$	280.3	$	130.3

(1) The terms of the Canadian credit facility have a revolving three year period expiring on May 30, 2010. Provident can extend the revolving period by an additional year, no earlier than 90 days and no later than 30 days prior to the end of the first year of the applicable three year revolving period. If the lenders do not extend the revolving period, or Provident chooses not to extend, the credit facility will be terminated and the loan balance will become due and payable in full on the maturity date. Management intends to extend the revolving period beyond the current maturity date.

Long-term debt and working capital

As at December 31, 2007 Provident had drawn on 71 percent of its term credit facilities of $1,125 million and U.S. $ 737.7 million as compared to 63 percent drawn on its $925 million and U.S. $158 million term credit facilities as at December 31, 2006. The increase in the level of bank debt was due to the increased scale of operations primarily due to acquisitions.

At December 31, 2007 Provident had letters of credit guaranteeing Provident’s performance under certain commercial and other contracts that totaled $35.9 million, increasing bank line utilization to 72 percent. The guarantees at December 31, 2006 totaled $31.9 million.

Provident’s working capital decreased by $166.3 million from $55.8 million to a deficit of $110.5 million as at December 31, 2007. The significant decrease is primarily due to a $155.7 million increase in net current financial derivative instrument liabilities, a $151.6 million increase in accounts payable including distribution payable and current portion of convertible debentures, partially offset by increased accounts receivable of $147.4 million.

The ratio of long-term debt to funds flow from operations in 2007 was 3.3 to one, compared to 2.3 to one in 2006. Fourth quarter funds flow from operations in 2007 was $177.6 million. The ratio of debt to annualized fourth quarter funds flow from operations was 2.2 to one, as compared to 2006 fourth quarter annualized debt to funds flow from operations of 2.0 to one. The increase reflects debt issued in connection with the Capitol Energy and USOGP natural gas asset acquisitions.

Trust units

On May 24, 2007, the Trust issued 25,490,197 Subscription Receipts at a price of $12.75 per Subscription Receipt for total proceeds of $325 million ($308.3 million net of issue costs). On June 7, 2007, an additional 3,823,530 Subscription Receipts were issued at a price of $12.75 on exercise of the underwriter’s over-allotment option, for additional proceeds of $48.8 million ($46.3 million net of issue costs). Each Subscription Receipt entitled the holder to receive one trust unit upon completion of the Capitol acquisition. The acquisition closed on June 19, 2007 at which time all the outstanding Subscription Receipts were converted into trust units. Proceeds from the issue were used to fund the Capitol acquisition.

On December 3, 2007 the Trust issued 6.3 million units (at an ascribed value of $76.6 million) as part of the consideration to acquire the outstanding shares of Triwest Energy Inc.

For the year ended December 31, 2007 the Trust issued 0.5 million units on conversion of convertible debentures (2006 – 1.3 million units). An additional 0.8 million units pursuant to the unit option plan were issued for the year ended December 31, 2007 (2006 – 0.9 million units). Under Provident’s Premium Distribution, Distribution Reinvestment (DRIP) and Optional Unit Purchase Plan program 4.5 million units were elected in 2007 and were issued or are to be issued representing proceeds of $50.5 million (2006 – 3.0 million units for proceeds of $36.9 million).

At December 31, 2007 management and directors held approximately 0.9 percent of the outstanding trust units.

Non-controlling interest – USOGP operations

A non-controlling interest arose from Provident’s June 15, 2004 acquisition of 92 percent of BreitBurn Energy Company L.P. (BreitBurn) of Los Angeles, California. Additional investments since June 2004 by Provident in BreitBurn have reduced the non-controlling interest percentage at December 31, 2007 to approximately 4.0 percent (2006 – 4.4 percent). Contributions by this non-controlling interest were nil in 2007 (2006 – $0.5 million). At December 31, 2007 the carrying amount of this non-controlling interest was $5.6 million (2006 - $3.9 million).

In the second quarter of 2006, a USOGP subsidiary began a land development project with a partner. The subsidiary has a 20 percent interest, with the partner holding 80 percent. Because the subsidiary stands to receive a majority share of the future proceeds, Provident is consolidating the results in its statements, with non-controlling interest. Contributions by the non-controlling interest total $3.9 million in 2007 (2006 - $3.7 million). At December 31, 2007 the carrying amount of this non-controlling interest was $5.4 million (2006 - $2.5 million).

In the fourth quarter of 2006, Provident’s subsidiary, BreitBurn Energy Partners, L.P. (the “MLP”) completed its initial public offering. BreitBurn transferred oil and gas properties comprising approximately half of its proved reserves and two thirds of its daily production to the MLP. The offering of 6.9 million common units at U.S. $18.50 per unit resulted in approximately 34 percent of the MLP held by partners not related to Provident. During the second quarter of 2007, the MLP issued 7.0 million common units to third parties for proceeds of $237.5 million. As a result of this transaction, Provident’s interest in the MLP decreased from approximately 66 percent to approximately 50 percent, resulting in a dilution gain of $98.6 million recorded on the consolidated statement of operations. During the fourth quarter of 2007, the MLP issued 38.0 million units in conjunction with the USOGP natural gas asset acquisition. The cash proceeds and ascribed value of these issued units totaled $1,142.2 million. As a result of this transaction, Provident’s interest in the MLP decreased from approximately 50 percent to approximately 22 percent, resulting in a dilution gain of $161.7 million recorded on the consolidated statement of operations. Provident continues to control the MLP through its 95.6 percent ownership of the general partner. The non-controlling interest balance increased by $1,119.4 million in 2007 reflecting the non-controlling interest ownership change from approximately 34 percent to approximately 78 percent. At December 31, 2007, the carrying value of this non-controlling interest was $1,089.1 million (2006 - $74.7 million).

	Year ended December 31,
Non-controlling interests - USOGP ($ 000s)	2007			2006
Non-controlling interests, beginning of year	$	81,111		$	11,885
Net (loss) income attributable to non-controlling interest		(35,666	)		2,995
Distributions to non-controlling interest		(35,846	)		(6,523	)
Investments by non-controlling interest		1,129,073			72,754
Foreign currency translation adjustment		(38,536	)		-
Non-controlling interests, end of year	$	1,100,136		$	81,111

Accumulated (loss) income attributable to non-controlling interest	$	(30,152	)	$	5,514

Capital expenditures and funding
Consolidated				Year ended December 31,
($ 000s)	2007			2006			% Change
Capital Expenditures and Funding

Capital Expenditures
Capital expenditures and reclamation fund contributions	$	(251,546	)	$	(193,183	)		30
Property acquisitions, net		(1,028,853	)		(481,625	)		114
Corporate acquisitions		(469,795	)		(1,036	)		45,247
Net capital expenditures	$	(1,750,194	)	$	(675,844	)		159

Funded By
Funds flow from operations net of declared distributions to unitholders and non-
controlling interest	$	99,057		$	142,676			(31	)
Increase in long-term debt		534,215			117,385			355
Issue of trust units, net of cost; excluding DRIP		362,418			220,225			65
DRIP proceeds		50,491			36,851			37
Contributions by non-controlling interests		683,100			135,829			403
Change in working capital, including cash, sale of assets and change in
investments		20,913			22,878			(9	)
Net capital expenditure funding	$	1,750,194		$	675,844			159

Capital expenditures were funded by a combination of funds flow from operations, debt and equity issued from treasury through public offerings, the DRIP program and contributions by non-controlling interest.

Provident expects approximately $23 million in leasehold improvements and furniture and equipment associated with the head office move in 2008. Up to December 31, 2007, $20.9 million has been incurred. Of this amount, $13.6 million has been allocated to the COGP business unit and $7.3 million has been allocated to Midstream. See individual operating segment sections for discussion of other capital expenditures.

Non-cash unit based compensation

Non-cash unit based compensation includes expenses or recoveries associated with Provident’s restricted and performance unit plan, unit option plan, unit appreciation rights and other unit based compensation plans. Provident accounts for the unit option plan using the fair value of the option at the time of issue. The other unit based compensation is recorded at the estimated fair value of the notional units granted. Compensation expense associated with the plans is recognized in earnings over the vesting period of each plan. The expense associated with each period is recorded as non-cash unit based compensation (a component of general and administrative expense). A portion is also allocated to operating expense. For the year ended December 31, 2007, Provident recorded unit based compensation expense of $30.9 million (2006 - $29.7 million) and made related cash payments of $15.7 million (2006 - $5.6 million). At December 31, 2007, the current portion of the liability totaled $22.2 million (December 31, 2006 - $18.2 million) and the long-term portion totaled $20.8 million (December 31, 2006 - $16.3 million).

COGP segment review

Crude oil and liquids price
COGP			Year ended December 31,
($ per bbl)	2007		2006		% Change

Oil per barrel
WTI (US$)	$	72.31	$	66.22		9
Exchange rate (from US$ to Cdn$)	$	1.07	$	1.13		(5	)
WTI expressed in Cdn$	$	77.67	$	74.83		4

Realized pricing before financial derivative instruments
Light/Medium oil	$	60.38	$	57.18		6
Heavy oil	$	41.85	$	36.80		14
Natural gas liquids	$	55.07	$	51.91		6
Crude oil and natural gas liquids	$	56.54	$	52.38		8
The above realized prices are net of transportation expense.

For the year ended December 31, 2007 COGP’s realized crude oil and natural gas liquids price, prior to the impact of financial derivative instruments, increased by eight percent to average $56.54 compared to $52.38 in 2006. The 2007 increase related to a nine percent higher US$ WTI crude oil price, narrower pricing differentials on all crude oil streams and a reduction in Provident’s heavy oil volumes as a percentage of its oil production mix price, partially offset by a stronger Canadian dollar.

Natural gas price

COGP			Year ended December 31,
($ per mcf)	2007		2006		% Change

AECO monthly index (Cdn$ per mcf)	$	6.59	$	6.98		(6	)

Corporate natural gas price per mcf before financial derivative instruments (Cdn$)	$	6.42	$	6.66		(4	)

The above prices are net of transportation expense.

For the year ended December 31, 2007 COGP’s realized natural gas price, excluding financial derivative instruments, decreased four percent as compared to 2006, comparable to the decrease in the benchmark AECO monthly index price. Provident markets approximately 25 percent of its natural gas to aggregators and the remaining 75 percent is sold to the market on daily or monthly indices, receiving prices that are based on the heat content of the natural gas. Provident’s realized prices and changes in prices will therefore differ from benchmark indices.

Production

COGP			Year ended December 31,
	2007		2006		% Change

Daily production
Crude oil - Light/Medium (bpd)		7,876		6,815		16
- Heavy (bpd)		1,921		2,057		(7	)
Natural gas liquids (bpd)		1,316		1,401		(6	)
Natural gas (mcfd)		92,378		82,469		12
Oil equivalent (boed) (1)		26,509		24,018		10
(1) Provident reports equivalent production converting natural gas to oil on a 6:1 basis.

For the year ended December 31, 2007, COGP production averaged 26,509 boed, a 10 percent increase compared to 24,018 boed in 2006. The increase is primarily a result of the two recent acquisitions, Capitol on June 19, 2007 and Triwest on December 3,

2007, the full year effect in 2007 of the acquisition of the Rainbow assets (Northwest Alberta) on August 31, 2006, and the production volumes added through drilling and optimization activities, partially offset by natural production declines. The Capitol acquisition became COGP’s newest core area, Dixonville, and the Triwest acquisition has been rolled up into the Southeast Saskatchewan core area.

Production for 2007 was weighted 58 percent natural gas, 35 percent medium/light crude oil and natural gas liquids and seven percent heavy oil. This compared to 2006 production weighted 57 percent natural gas, 34 percent medium/light oil and natural gas liquids and nine percent heavy oil. Year-over-year, the change in mix reflected the two acquisitions of Capitol on June 19, 2007 and Triwest on December 3, 2007 which were primarily light/medium crude oil production, and the full year effect in 2007 of the August 31, 2006 acquisition of the Rainbow assets, which were primarily natural gas.

COGP’s production summarized by core areas is as follows:
			Year ended December 31,
COGP	2007		2006		% Change
Daily Production - by area (boed) (1)
West Central Alberta		6,997		8,168		(14	)
Southern Alberta		5,622		6,237		(10	)
Northwest Alberta		4,905		1,545		217
Dixonville (2)		2,058		-		-
Southeast Saskatchewan		1,769		1,731		2
Southwest Saskatchewan		1,726		2,624		(34	)
Lloydminster		3,418		3,622		(6	)
Other		14		91		(85	)
		26,509		24,018		10

(1)	Provident reports equivalent production converting natural gas to oil on a 6:1 basis.

(2)	Represents production from June 19, 2007 (date of Capitol Energy Resources Ltd. acquisition).

Internal development activities included 103 net wells drilled for the year ended December 31, 2007 with a 98 percent success rate. COGP’s drilling activities in 2007 were more focused on crude oil compared to 2006. Provident’s newest core area, Dixonville had a successful drilling program although there was some unexpected production tie-in delays from cold weather which resulted in some additional downtime. Optimization of the production and facilities are ongoing. Northwest Alberta’s production for 2007 represented a full year of production from the Rainbow asset acquisition. Northwest Alberta’s successful 2006/2007 winter drilling program resulted in additional production in the first half of the year that was offset by the impact of unfavorable weather in the fourth quarter of 2007 causing a unit compressor and pump jack failure. Southeast Saskatchewan had favorable production results from its optimization activities and better than expected results from oil well drilling activities. Drilling and production results from the Triwest assets exceeded internal expectations. Provident’s other core areas remain active. In southern Alberta, Provident actively managed production declines through shallow gas well drilling. In Lloydminster, Provident was successful with its workover activities and reactivation of oil wells resulting in production increases that were offset by higher than expected declines. In West Central Alberta, Provident continues its strategy of farming out high risk exploration land to generate cash flow with minimal or no capital outlay.

Revenue and royalties
COGP				Year ended December 31,
($ 000s except per boe and mcf data)	2007			2006 %			Change

Oil
Revenue	$	202,909		$	169,852			19
Realized loss on financial derivative instruments		(7,905	)		(3,193	)		148
Royalties		(39,211	)		(32,567	)		20
Net revenue	$	155,793		$	134,092			16
Net revenue (per barrel)	$	43.57		$	41.41			5
Royalties as a percentage of revenue		19.3	%		19.2	%

Natural gas
Revenue	$	216,626		$	200,584			8
Realized gain on financial derivative instruments		9,633			7,564			27
Royalties		(41,154	)		(42,200	)		(2	)
Net revenue	$	185,105		$	165,948			12
Net revenue (per mcf)	$	5.49		$	5.51			-
Royalties as a percentage of revenue		19.0	%		21.0	%

Natural gas liquids
Revenue	$	26,451		$	26,545			-
Royalties		(6,681	)		(6,458	)		3
Net revenue	$	19,770		$	20,087			(2	)
Net revenue (per barrel)	$	41.16		$	39.28			5
Royalties as a percentage of revenue		25.3	%		24.3	%

Total
Revenue	$	445,986		$	396,981			12
Realized gain on financial derivative instruments		1,728			4,371			(60	)
Royalties		(87,046	)		(81,225	)		7
Net revenue	$	360,668		$	320,127			13
Net revenue (per boe)	$	37.27		$	36.52			2
Royalties as a percentage of revenue		19.5	%		20.5	%

Note: the above revenue, net revenue and net revenue per boe figures are presented net of transportation expenses.

For the year ended December 31, 2007 COGP production revenue was $446.0 million, an increase of 12 percent from $397.0 million in 2006. The increase in revenue was a result of the 10 percent increase in production and higher realized crude oil and natural gas liquids prices. The increase was partially offset by a lower realized natural gas price. Royalties as a percentage of revenue have remained relatively constant at 19.5 percent. The preceding factors, as well as the $1.7 million realized gain on financial derivative instruments compared to a $4.4 million gain in 2006, account for net revenue of $360.7 million in 2007, 13 percent higher than the $320.1 million recorded in 2006.

Net revenue per boe in 2007 increased two percent to $37.27 from $36.52 in 2006 resulting primarily from higher realized crude oil and natural gas liquids prices and a higher percentage of production from liquids, partially offset by a lower realized gas price and a decrease in the realized gain on financial derivative instruments.

Production expenses
COGP			Year ended December 31,
($ 000s, except per boe data)	2007		2006		% Change

Production expenses	$	112,387	$	97,626		15
Production expenses (per boe)	$	11.62	$	11.14		4

For the year ended December 31, 2007 production expenses increased 15 percent to $112.4 million from $97.6 million and increased by four percent on a per unit basis to $11.62 per boe from $11.14 per boe in the prior year. The increase was primarily due to the increase in production of 10 percent. On a per boe basis, operating expenses continued to increase in a number of categories including well servicing, maintenance, fluid hauling, and power and fuel. Cost increases included increased power costs in July and August 2007 driven by hot weather in Southern Alberta and West Central Alberta, increased road maintenance costs in Northwest Alberta due to significant wet weather during the summer months, and higher than expected ice road maintenance in the winter months. Cost increases in power and fuel, chemicals and well servicing reflect higher commodity prices and labour costs.

Operating netback
COGP				Year ended December 31,
($ per boe)	2007			2006			% Change
Netback per boe
Gross production revenue	$	46.09		$	45.29			2
Royalties		(9.00	)		(9.27	)		(3	)
Operating costs		(11.62	)		(11.14	)		4
Field operating netback		25.47			24.88			2
Realized gain on financial derivative instruments		0.18			0.50			(64	)

Operating netback after realized financial derivative instruments	$	25.65		$	25.38			1

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

The 2007 field operating netback of $25.47 per boe was two percent above the $24.88 per boe for the prior year. This reflects COGP’s increased realized crude oil and natural gas liquids prices and an increase in COGP’s production mix of higher priced light/medium crude oil to 30 percent in 2007 from 28 percent in 2006 and a decrease in lower netback heavy oil to seven percent in 2007 from nine percent in 2006. This was partially offset by lower realized natural gas prices due to the decrease in benchmark AECO monthly index price and four percent per boe higher operating costs as explained above. Royalties, which are price sensitive, decreased by three percent on a boe basis reflecting lower natural gas prices. The 2007 operating netbacks after financial derivative instruments increased by one percent to $25.65 from $25.38 in the prior year due to the preceding factors as well as the realized gain on financial derivative instruments of $0.18 per boe compared to $0.50 per boe in the prior year.

General and administrative

COGP			Year ended December 31,
($ 000s, except per boe data)	2007		2006		% Change

Cash general and administrative	$	27,102	$	24,065		13
Non-cash unit based compensation		3,698		4,320		(14	)
	$	30,800	$	28,385		9

Cash general and administrative (per boe)	$	2.80	$	2.75		2

For the year ended December 31, 2007, cash general and administrative expenses were $2.80 per boe, compared to $2.75 per boe in 2006. The increase in cash general and administrative expenses reflects additional provisions for short-term incentive compensation reflecting the performance of the Trust in relation to established benchmarks.

Capital expenditures

COGP	Year ended December 31,
($ 000s)	2007		2006
Capital expenditures - by category
Geological, geophysical and land	$	4,519	$	4,508
Drilling and recompletions		113,425		56,807
Facilities and equipment		13,378		6,353
Other capital		14,887		2,420
Total additions	$	146,209	$	70,088
Capital expenditures - by area
West central Alberta	$	9,051	$	11,280
Southern Alberta		13,079		17,619
Northwest Alberta		35,993		4,883
Dixonville		43,801		-
Southeast Saskatchewan		5,069		1,941
Southwest Saskatchewan		15,196		25,677
Lloydminster		9,235		7,262
Office and other		14,785		1,426
Total additions	$	146,209	$	70,088

Property acquisitions, net	$	13,050	$	483,633

In 2007, Provident’s COGP business unit spent $131.4 million on capital expenditures before office and other capital costs. Internal development activities included 103 net wells drilled for the year ended December 31, 2007 with a 98 percent success rate. COGP’s drilling activities in 2007 were more focused on crude oil compared to 2006. Provident spent $43.8 million in the newest core area, Dixonville, primarily on drilling and completion activities utilizing three drilling rigs in the third and fourth quarters of 2007, which resulted in 39.0 net wells drilled. Provident spent $36.0 million in Northwest Alberta, primarily on drilling and completion activities and facility work which included 27.6 net wells drilled, the infrastructure and tie-in activities associated with the 2006/2007 winter drilling program and preparation work to start the 2007/2008 winter drilling program. In the Southeast and Southwest Saskatchewan core areas, $20.3 million was spent which included 20.1 net wells drilled. At the beginning of the year, the drilling program was primarily focused on the Southwest Saskatchewan shallow gas drilling program, however as gas prices declined during the year, the shallow gas drilling program was reduced significantly and capital was shifted to oil drilling in Dixonville and to the Triwest assets and facility opportunities in other areas. Southeast Saskatchewan spending was focused on optimization activities and oil drilling activity including additional capital for the continuation of the drilling program on the Triwest assets. In Southern Alberta, $13.1 million was primarily spent on drilling activity and recompletions which included 9.9 net wells drilled and on facility upgrades and infrastructure work. In West central Alberta, $9.1 million was spent largely on non-operated drilling and completion activities which included 3.0 net wells drilled, facility and infrastructure work, and recompletion activities. In the Lloydminster core area, $9.2 million was spent primarily on drilling and recompletion activities which included 3.4 net wells drilled and facility work.

Additions to proved plus probable reserves before revisions through internal capital replaced approximately 44 percent of annual production.

In 2007, COGP also spent $13.1 million on property acquisitions primarily on acquiring additional working interests in Northwest Alberta and Southern Alberta.

In addition, $14.8 million was spent on office and other in 2007, primarily on office equipment and furniture for the new office space to be occupied in 2008.

Depletion, depreciation and accretion (DD&A)

COGP			Year ended December 31,
($ 000s, except per boe data)	2007		2006		% Change

DD&A	$	256,723	$	168,953		52
DD&A (per boe)	$	26.53	$	19.27		38

The COGP DD&A rate of $26.53 per boe increased 38 percent for 2007 compared to $19.27 per boe in 2006. The increase was primarily as a result of the two acquisitions of Capitol and Triwest in 2007 and the impact of the Rainbow asset acquisition in the third quarter of 2006 into the full year of 2007. These recent COGP acquisitions differed from earlier acquisitions in that they included significant reserves that were not yet proved. Since depletion calculations are based on proved reserves, acquisitions with unproved reserves generally result in higher depletion rates. This phenomenon, combined with the higher cost of acquiring or drilling proved reserves in western Canada in an environment with higher commodity prices and increased drilling costs, will be reflected in the DD&A rate going forward.

In 2007, DD&A also includes accretion expense associated with asset retirement obligation of $2.5 million (2006 - $1.9 million).

As part of the reconciliation of Provident’s financial statements to United States generally accepted accounting principles (U.S. GAAP), disclosed in note 19 to consolidated financial statements, the Trust has reflected additional depletion in 2007 of $181.6 million (2006 – $382.2 million) and a related future income tax recovery of $52.2 million (2006 - $114.7 million) as a result of the application of the U.S. GAAP ceiling test. These changes were not required under Canadian generally accepted accounting principles.

USOGP segment review

The USOGP business unit incorporates activities from certain Provident subsidiaries comprising an oil and gas production organization based in Los Angeles, California.

In October 2006, Provident, through its USOGP subsidiaries, completed its initial public offering (“IPO”) of 6.9 million units at USD $18.50 per unit of BreitBurn Energy Partners, L.P. (the “MLP”). This master limited partnership (NASDAQ-BBEP) is a U.S. public, tax flow-through entity similar to Canadian royalty and income trusts such as Provident. These entities, however, are not affected by the new Canadian legislation taxing trust distributions commencing in 2011. Selected producing assets in the Los Angeles basin in California and in Wyoming were transferred to the MLP. The previously existing subsidiary (“BreitBurn”), of which Provident owns approximately 96 percent, continues to operate assets in the Los Angeles basin at West Pico and other areas, and the Orcutt field in the Santa Maria basin.

In May 2007, the MLP completed two oil and gas property acquisitions, one in Florida for cash consideration of USD $108.1 million and one in California for cash consideration of USD $92.5 million. The acquisitions were financed by the issue of 7.0 million common units by the MLP to institutional investors at an average price of USD $31.58 per unit. As a result of these unit issues, Provident’s interest in the MLP decreased from approximately 66 percent to approximately 50 percent, resulting in a dilution gain of $98.6 million recorded in the consolidated statement of operations in the second quarter of 2007.

On November 1, 2007, the MLP completed the acquisition of natural gas, oil and related assets in Michigan, Indiana and Kentucky from Quicksilver Resources Inc. (“Quicksilver”) in exchange for U.S. $750 million in cash and 21.3 million MLP units. The cash portion of the acquisition was partially financed through the issuance of 16.7 million MLP units, at U.S. $27.00 per unit. As a result of these unit issues, Provident’s interest in the MLP decreased from approximately 50 percent to approximately 22 percent, resulting in a dilution gain of $161.7 million recorded in the consolidated statement of operations in the fourth quarter of 2007. Provident continues to control and consolidate the MLP.

The USOGP segment includes the consolidated results of 100 percent of the MLP and BreitBurn. Non-controlling interests are comprised mainly of the public ownership in the MLP, and to a lesser extent the ownership interests of the managers in the MLP and BreitBurn, as well as third party investment in USOGP’s land development project which commenced in 2006.

Crude oil, natural gas liquids and natural gas pricing

USOGP			Year ended December 31,
($ per bbl, except as noted)	2007		2006		% Change

Realized pricing before financial derivative instruments
Light/medium oil and natural gas liquids (Cdn$ per bbl)	$	65.54	$	63.24		4
Natural Gas (Cdn $ per mcf)	$	7.22	$	6.58		10

Realized pricing of light/medium oil and natural gas liquids were four percent higher in 2007 when compared to 2006, equivalent to the increase in WTI, expressed in Canadian dollars, over the same period.

Realized natural gas pricing before financial derivative instruments was up 10 percent in 2007 when compared to 2006. The increase was primarily associated with the increase in Henry Hub pricing. In addition, the newly acquired Michigan properties have favorable natural gas supply/demand characteristics as the state has been importing an increasing percentage of its natural gas.

Production
			Year ended December 31,
USOGP	2007		2006		% Change
Daily production - by product
Crude oil - Light/Medium (bpd)		9,557		7,299		31
Natural gas liquids (bpd)		105		18		483
Natural gas (mcfd)		14,773		2,422		510
Oil equivalent (boed) (1)		12,124		7,721		57
(1) Provident reports equivalent production converting natural gas to oil on a 6:1 basis.

			Year ended December 31,
USOGP	2007		2006		% Change
Daily Production - by area (boed) (1)
Los Angeles		4,203		3,901		8
Santa Maria - Orcutt		1,555		1,491		4
Wyoming		2,554		2,329		10
Texas		349		-		-
Florida		1,099		-		-
Michigan/Indiana/Kentucky		2,364		-		-
		12,124		7,721		57
(1) Provident reports equivalent production converting natural gas to oil on a 6:1 basis.

USOGP production increased 4,403 boe per day or 57 percent in 2007 when compared to 2006. The increase is primarily attributable to acquisitions made by USOGP in 2007, which included fields in Los Angeles, Florida, Texas, Michigan, Indiana and Kentucky. Production from the MLP for the year ended December 31, 2007 was 9,518 boed, while production from BreitBurn was 2,606 boed.

Revenue and royalties

The following table outlines USOGP revenue and royalties by product line. The table excludes revenues earned from operating certain properties ($1.3 million in the year ended December 31, 2007 (2006 - $1.0 million)) on behalf of third parties. The table also excludes revenue from the sale of inventory acquired as part of the Florida acquisition in May 2007, amounting to $12.8 million in the year ended December 31, 2007.

USOGP				Year ended December 31,
($ 000s, except per boe and mcf amounts)	2007			2006			% Change
Oil and natural gas liquids
Revenue	$	222,263		$	169,322			31
Realized loss on financial derivative instruments		(7,959	)		(2,505	)		218
Royalties		(25,294	)		(16,554	)		53
Net revenue	$	189,010		$	150,263			26
Net revenue (per bbl)	$	55.73		$	56.26			(1	)
Royalties as a percentage of revenue		11.4	%		9.8	%
Natural gas
Revenue	$	38,930		$	5,820			569
Royalties		(6,360	)		(761	)		736
Net revenue	$	32,570		$	5,059			544
Net revenue (per mcf)	$	6.04		$	5.72			6
Royalties as a percentage of revenue		16.3	%		13.1	%
Total
Revenue	$	261,193		$	175,142			49
Realized loss on financial derivative instruments		(7,959	)		(2,505	)		218
Royalties		(31,654	)		(17,315	)		83
Net revenue	$	221,580		$	155,322			43
Net revenue (per boe)	$	51.65		$	55.12			(6	)
Royalties as a percentage of revenue		12.1	%		9.9	%

Note: the above revenue, net revenue and net revenue per boe figures are presented net of transportation expenses. Per boe figures are calculated using sales volumes, which differ from production volumes due to changes in inventory levels at the Florida properties, acquired in the second quarter of 2007.

For the year ended December 31, 2007 revenue was 49 percent higher than the year ended December 31, 2006 primarily due to increases in sales volumes from the acquisitions. Royalties as a percentage of revenue have increased as royalties at the Michigan, Wyoming, Texas and Florida properties are higher than those incurred at the Southern California operations. Net revenue for the year ended December 31, 2007 was 43 percent higher than the year ended December 31, 2006 due to all the

acquisitions in 2007 and the higher crude oil and natural gas prices. These increases were partially offset by higher realized losses on financial derivative instruments in 2007 compared to 2006.

Production expenses
USOGP			Year ended December 31,
($ 000s, except per boe amounts)	2007		2006		% Change
Production expenses	$	81,699	$	52,008		57
Production expenses (per boe)	$	19.04	$	18.45		3

Note: Per boe figures are cal cul ated using sales volumes, which differ from production volumes due to changes in inventory level s at the Florida properties, acquired in the second quarter of 2007.

Production expenses increased 57 percent to $81.7 million in 2007 compared to $52.0 million in 2006. Production expenses per boe have increased three percent to $19.04 in 2007 from $18.45 in 2006. This change reflects both the increase in utilities and other costs and services driven by the high commodity price environment as well as higher operating cost crude oil wells that were returned to production to take advantage of continuing strong crude oil prices. These increases were largely offset by lower production costs per boe from the newly acquired Michigan properties.

Operating netback
USOGP				Year ended December 31,
($ per boe)	2007			2006			% Change
USOGP oil equivalent netback per boe
Gross production revenue	$	60.88		$	62.15			(2	)
Royalties		(7.38	)		(6.14	)		20
Operating costs		(19.04	)		(18.45	)		3
Field operating netback	$	34.46		$	37.56			(8	)
Realized loss on financial derivative instruments		(1.85	)		(0.89	)		108
Operating netback after realized financial derivative instruments	$	32.61		$	36.67			(11	)

Note: Per boe figures are calculated using sales volumes, which differ from production volumes due to changes in inventory levels at the Florida properties, acquired in the second quarter of 2007.

USOGP operating netbacks remained strong throughout 2007 due to high commodity prices, partially offset by higher realized losses on financial derivative instruments when compared to 2006 and increased production costs and royalties.

General and administrative
USOGP			Year ended December 31,
($ 000s, except per boe amounts)	2007		2006		% Change
Cash general and administrative	$	45,188	$	26,519		70
Non-cash unit based compensation		5,950		12,476		(52	)
	$	51,138	$	38,995		31
Cash general and administrative (per boe)	$	10.21	$	9.41		9

For the year ended December 31, 2007, cash general and administrative expenses were $45.2 million (2006 – $26.5 million). 2007 cash general and administrative expense includes $13.9 million or $3.14 per boe (2006 - $5.0 million or $1.75 per boe) related to payments associated with unit based compensation. The expense was accrued in 2006 as non-cash unit based compensation, consequently there is an offsetting reduction in non-cash unit based compensation in 2007, when the payments were made. Excluding these payments, cash general and administrative expenses were $31.3 million or $7.07 per boe for the year ended December 31, 2007 compared to $21.5 million or $7.63 per boe for the same period in 2006. The increase was due to increased costs associated with regulatory compliance as well as increased staffing levels required for the rapidly growing public MLP.

Non-cash unit based compensation for the year ended December 31, 2007 was $6.0 million (2006 - $12.5 million expense). Year-to-date 2007 cash payments related to unit based compensation were $13.9 million compared to $5.0 million in 2006. Payment of unit based compensation is recorded as cash general and administrative expense with an offsetting reduction in

non-cash unit based compensation. Excluding this payment, non-cash unit based compensation was $19.9 million for the year ended December 31, 2007 (2006 - $17.5 million). The increase in expense in 2007 reflects higher staffing levels due to the acquisitions as well as strong MLP performance in 2007.

Capital expenditures
USOGP	Year ended December 31,
($ 000s)	2007		2006
Capital expenditures - by category
Geological, geophysical and land	$	1,715	$	104
Drilling and recompletions		42,196		30,943
Facilities and equipment		18,691		18,486
Other capital		6,407		4,804
Total additions	$	69,009	$	54,337
Property acquisitions, net	$	1,015,803	$	(2,008	)

USOGP capital expenditures for the year ended December 31, 2007 totaled $69.0 million. Of this total, $58.8 million related to drilling, optimization and facility upgrades at Orcutt, Wyoming, Santa Fe Springs and the newly acquired Michigan properties.

In 2007, USOGP completed property acquisitions of $1,015.8 million. $115.6 million represents the Florida acquisition and $98.9 million was spent on an acquisition in California. An additional $37.6 million was directed at acquiring additional wells in Texas, Los Angeles and Wyoming. $763.7 million represents the cash portion of the USOGP natural gas asset acquisition.

Depletion, depreciation and accretion (DD&A)
USOGP			Year ended December 31,
($ 000s, except per boe amounts)	2007		2006		% Change
DD&A	$	50,253	$	31,058		62
DD&A (per boe)	$	11.36	$	11.02		3

The USOGP’s DD&A rate is low due to the long-lived nature of the assets. On a per boe basis the DD&A rate was up $11.36 or three percent in 2007 when compared to 2006. The change reflects higher depletion costs related to the recent producing property acquisitions.

Recent developments

USOGP continues to progress on its acquisition integration. The MLP expects to complete its system integration relating to the USOGP natural gas asset acquisition in the second quarter of 2008.

Midstream business segment review

The Midstream business

Empress East

Redwater West

Commercial Services

The Empress East business line is comprised of the following core assets:

• Approximately 2.0 Bcfd of extraction capacity at Empress, Alberta. This is the combination of 67.5 percent ownership of the 1.2 Bcfd capacity Provident Empress NGL Extraction plant, 12.4 percent ownership in the 1.1 Bcfd capacity ATCO Plant, 8.3 percent ownership in the 2.4 Bcfd capacity Spectra Plant and 33.0 percent ownership in the 2.7 Bcfd capacity BP Empress 1 Plant.

• 100 percent ownership of a 50,000 bpd debutanizer at Empress, Alberta.

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

• In Sarnia, Ontario, 10.3 percent ownership of an approximately 150,000 bpd fractionator, 1.7 mmbbl of raw product storage capacity and 18 percent of 5.0 mmbbl of finished product storage and rail, truck and pipeline terminalling. An additional 0.5 mmbbls of specification product storage is also available in the Sarnia area.

• A propane distribution terminal at Lynchburg, Virginia.

• A rail car fleet of approximately 350 rail cars.

The Redwater West business line is comprised of the following core assets:

• 100 percent ownership of the Redwater NGL Fractionation Facility, incorporating a 65,000 bpd fractionation, storage and transportation facility that includes 12 pipeline receipt and delivery points, railcar loading facilities with direct access to CN rail and indirect access to CP rail, two propane truck loading facilities, six million gross barrels of salt cavern storage, and a 60,000 bpd condensate rail offloading facility with a 300 railcar storage yard. The facility can process high-sulphur NGL streams and is one of only two ethane-plus fractionation facilities in western Canada capable of extracting ethane from the natural gas liquids stream.

• Approximately 7,000 bpd of leased fractionation and storage capacity at other facilities.

• 43.3 percent direct ownership and 100 percent control of all products from the 38,500 bpd Younger NGL extraction plant located at Taylor in northeastern British Columbia. The Younger plant supplies local markets as well as Provident’s Redwater plant near Edmonton.

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

• A rail car fleet of approximately 485 rail cars.

The Commercial Services business line:

The Commercial Services business line includes services such as fractionation, storage, and loading at Provident’s Redwater facility on a fee basis. It also includes pipeline tariff income from Provident’s ownership of the Liquids Gathering System in Northwest Alberta which flows into Pembina’s pipeline from LaGlace to Redwater. Provident also collects tariff income from its

50 percent ownership in the Kerrobert Pipeline which transports NGLs from Empress to Kerrobert for injection into the Enbridge pipeline for delivery to Sarnia. Further, Provident owns a debutanizer at its Empress facility, which removes condensate from the NGL mix for sale as a diluent to blend with heavy oil. This service is provided to a major energy company on a long term cost of service basis. Earnings from this business line of the Midstream segment have little direct exposure to market prices volatility and are thus relatively stable.

Long term contracts

At the Redwater facility, a significant portion of the available propane plus capacity is contracted through a long term fee for service arrangement with third parties.

The ethane produced from Provident’s facilities at Empress and Redwater is largely sold under long term contracts.

Provident has a long term contract on a cost of service basis for the majority of its 50,000 bbl/d Empress debutanizer facility. Provident also has a long term contract for 500,000 barrels of specification product storage in the Sarnia area.

Also, see commitments disclosure in note 15 to the consolidated financial statements.
2007 Midstream business unit results can be summarized as follows:
				Year ended December 31,
($ 000s)	2007			2006			% Change
Empress East Margin	$	183,565		$	133,549			37
Redwater West Margin		94,600			75,686			25
Commercial Services Margin		54,649			46,695			17
Gross operating margin		332,814			255,930			30
Realized loss on financial derivative instruments		(74,474	)		(15,406	)		383
Cash general and administrative expenses		(28,669	)		(23,621	)		21
Foreign exchange (loss) gain and other		(3,996	)		2,728			-
Midstream EBITDA	$	225,675		$	219,631			3
Note: Certain comparative amounts have been reclassified to conform with the current year presentation.
Gross operating margin

The Empress East business line extracts NGLs from natural gas at the Empress straddle plants and sells finished products into markets in Central Canada and the Eastern United States. The margin in this business is determined primarily by the “frac spread ratio”, which is the ratio between crude oil prices and natural gas prices. The higher the ratio, the better this business line will perform. There is also a differential between propane, butane and condensate prices and crude oil prices which can change prices received and margins realized for Midstream products separate from frac spread ratio changes. The 2007 margin was $183.6 million compared to $133.5 million in 2006. The increase reflects approximately 10 percent higher propane-plus prices and lower transportation related costs, partially offset by five percent lower propane-plus sales volumes. Also, the 2006 gross operating margin includes the impact of a $5.2 million repayment incurred under the fractionation spread support program.

The Redwater West business line purchases an NGL mix from various producers and fractionates it into finished products at the Redwater fractionation facility near Edmonton, Alberta. Because the feedstock for this business line is primarily NGL mix rather than natural gas, the frac spread ratio has a smaller impact on margin than in the Empress East business line. In 2007, the margin for this business line was $94.6 million (2006 - $75.7 million). The increase in margin was primarily due to an increase in propane-plus sales volumes and a 10 percent increase in propane-plus prices.

The Commercial Services business line generates income from stable fee-for-service contracts to provide fractionation, storage, loading, and marketing services to upstream producers. Income from pipeline tariffs from Provident’s ownership in NGL pipelines is also included in this business line. In 2007, the margin for this business line was $54.6 million (2006 - $46.7 million). The increase in the margin is due to increased revenue associated with the condensate loading/offloading facility at Redwater which operated for a full year in 2007.

Operations – Midstream NGL sales volumes

Midstream sold 120,785 bpd in 2007, up five percent when compared with 2006.

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

For 2007, EBITDA increased $6.0 million or three percent from $219.6 million in 2006. A $76.9 million increase in gross operating margin as described above was tempered by a $59.1 million increase in realized losses on financial derivative instruments and higher cash general and administrative and other costs. The increased cost associated with the financial derivative instruments in 2007 is offset by the realized product margin during the year. Funds flow from operations for 2007 was $178.4 million, a decrease of $6.0 million below the $184.4 million in 2006. The decrease in funds flow from operations reflects the higher EBITDA offset by higher interest costs due to increased corporate long-term debt balances, and higher taxes.

Cash general and administrative expenses and other were $28.7 million for 2007 (2006 - $23.6 million) reflecting additional provisions for short-term incentive compensation due to the performance of the Trust in relation to established benchmarks.

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

Fractionation spread support program

As part of the December 2005 Midstream NGL Acquisition, the vendor agreed to provide a near-term fractionation spread support program. The program provides Provident with up to $75 million of support in 2006 and up to October 31, 2007 if the fractionation spread ratio is below historic levels. This program was intended to ensure that Provident achieves the long-term average fractionation spread ratio that the NGL business has attained historically. There was no activity under this agreement in 2007 or the last three quarters of 2006. In the first quarter of 2006, there was a repayment of $5.2 million that was received in the fourth quarter of 2005. The program has now expired.

Capital expenditures

Midstream capital expenditures in 2007 totaled $31.9 million. In 2007, $5.3 million was spent on a new condensate offloading and terminalling facility, expansion to the recently completed truck loading facilities, and continued development of cavern storage. In addition, $13.9 million was added to capitalized line-fill, $4.5 million was spent on sustaining capital requirements and $8.2 million was spent primarily on office furniture and equipment for the new office space to be occupied in 2008.

Foreign ownership

Based on information received from our transfer agent and financial intermediaries in January 2008, an estimated 85 percent of our outstanding trust units are held by non-residents. However, this estimate may not be accurate as it is based on certain assumptions and data from the securities industry that does not have a well-defined methodology to determine the residency of beneficial holders of securities.

The Trust qualifies as a Mutual Fund Trust under the Canadian Income Tax Act because substantially all the value of its asset portfolio is derived from non-taxable Canadian properties, comprised principally of royalties and interest on inter-company debt. Provident monitors on an ongoing basis the value of its asset portfolio to confirm that substantially all of the value of its asset portfolio is derived from non-taxable Canadian properties.

On September 17, 2003, Canadian unitholders approved an amendment to the Trust’s Trust Indenture providing that residency restriction provisions need not be enforced while the Trust continues to qualify as a Mutual Fund Trust under Canadian tax legislation. To allow Provident to remain a Mutual Fund Trust and to execute a business plan that maximizes unitholder returns without regard to the types of assets the Trust may hold, the approved amendment provides for Provident’s Board of Directors to have sole discretion to determine whether and when it is appropriate to reduce or limit the number of trust units held by non-residents of Canada.

Critical accounting policies

Provident’s accounting policies are described in note 2 to the consolidated financial statements. Certain accounting policies are identified as critical accounting policies because they form an integral part of Provident’s financial position. They also require management to make judgments and estimates based on conditions and assumptions that are inherently uncertain. These accounting policies could result in materially different results should the underlying assumptions or conditions change.

Management assumptions are based on Provident’s historical experience, management’s experience, and other factors that, in management’s opinion, are relevant and appropriate. Management assumptions may change over time, as further experience is gained or as operating conditions change.

Details of Provident’s critical accounting policies are as follows:

Property, plant and equipment

Provident follows the full cost method of accounting, whereby all costs associated with the acquisition and development of oil and natural gas reserves are capitalized. Utilization of the full cost method of accounting requires the use of management estimates and assumptions for amounts recorded for depletion and depreciation of property, plant and equipment as well as for the ceiling test.

The provision for depletion and depreciation is calculated using the unit of production method based on current production divided by Provident’s share of estimated total proved oil and natural gas reserve volumes before royalties. The recoverability of a cost centre is tested by comparing the carrying value of the cost centre to the sum of the undiscounted cash flows expected from the cost centre. If the carrying value is not recoverable the cost centre is written down to its fair value.

Proved reserves are an estimate, under existing reserve evaluation polices, of volumes that can reasonably be expected to be economically recoverable under existing technology and economic conditions. Changes in underlying assumptions or economic conditions could have a material impact on Provident’s financial results. To mitigate these risks, management utilizes McDaniel & Associates Consultants Ltd., an independent engineering firm, to evaluate Provident’s Canadian reserves. For Provident’s U.S. based assets, management utilizes Netherland, Sewell & Associates, Inc., and Schlumberger Data & Consulting Services, independent engineering firms, to evaluate reserves.

Estimates of future production, oil and natural gas prices and future costs used in the ceiling test are, by their very nature, subject to uncertainty and changes in underlying assumptions could have a material impact on Provident’s financial results.

Asset retirement obligation

Under the asset retirement obligation (ARO) standard, the fair value of asset retirement obligations is recorded as a liability on a discounted basis, when incurred. The value of the related assets is increased by the same amount as the liability and depreciated over the useful life of the asset. Over time the liability is adjusted for the change in present value of the liability or as a result of changes to either the timing or amount of the original estimate of undiscounted future cash flows.

Asset retirement obligation requires that management make estimates and assumptions regarding future liabilities and cash flows involving environmental reclamation and remediation. Such assumptions are inherently uncertain and subject to change over time due to factors such as historical experience, changes in environmental legislation or improved technologies. Changes in underlying assumptions, based on the above noted factors, could have a material impact on Provident’s financial results.

Change in accounting policies

Financial instruments and comprehensive income

Effective January 1, 2007, Provident adopted the requirements of the Canadian Institute of Chartered Accountants (“CICA”) related to the new financial instruments accounting framework, which encompasses the following new CICA Handbook sections: 3855 Financial Instruments – Recognition and Measurement, 1530 Comprehensive income, and 3861 Financial Instruments – Disclosure and Presentation. The CICA Handbook section 3865 Hedges is effective January 1, 2007, however, Provident has elected not to apply hedge accounting, consistent with prior periods.

These new Handbook sections provide comprehensive requirements for the recognition and measurement of financial instruments, and introduce a new component of equity referred to as accumulated other comprehensive income (“AOCI”). In accordance with the transitional provisions of all of the new sections, the comparative interim consolidated financial statements have not been restated, except that the “Cumulative translation adjustment” has been reclassified to “Accumulated other comprehensive income”.

Under these new standards, all financial instruments, including derivatives, are recognized on the Trust’s Consolidated Balance Sheet. Derivatives are measured at fair value with unrealized gains and losses reported in net income. Investments are measured at fair value, with reference to published price quotations, and unrealized gains and losses are reported in AOCI. The Trust’s other financial instruments (accounts receivable, accounts payable, and long-term debt) are measured at amortized cost using the effective interest rate method. Transaction costs are included with the associated financial instrument and amortized accordingly.

Several adjustments in the Trust’s consolidated financial statements were required upon transition to the new financial instruments framework, which were the following:

Long-term debt and deferred financing charges

Prior to the adoption of the new standards, financing charges related to long-term debt were included in “Deferred financing charges” on the Trust’s Consolidated Balance Sheet, and recognized in net income over the life of the debt.

Under the transitional provisions of Handbook section 3855 Financial Instruments – Recognition and Measurement, the Trust’s long-term debt – revolving credit facilities is now recorded at amortized cost using the effective interest rate method. The related financing charges have been included in the cost of the long-term debt. As a result of these changes, “Deferred financing charges” of $3.0 million, and prepaid interest of $8.5 million, which were previously recorded as assets of the Trust, were reclassified to “Long-term debt – revolving credit facilities” on the Consolidated Balance Sheet. The accounting treatment for “Long-term debt – convertible debentures” is the same as in prior periods, except that related deferred financing charges are now included in the carrying amount. Deferred financing charges of $9.4 million were reclassified to “Long-term debt – convertible debentures” on the Consolidated Balance Sheet.

Statement of comprehensive income

The consolidated financial statements now include a new Consolidated Statement of Comprehensive Income and Accumulated Other Comprehensive Income. Other comprehensive income includes foreign currency translation adjustments relating to self-sustaining foreign operations and unrealized gains and losses on available-for-sale investments, net of the related future income tax on those items.

Equity

In 2005, the CICA issued Section 3251 “Equity”. This Section replaces Section 3250 “Surplus” and Section requires an entity to present separately each of the changes in equity during the period, including comprehensive income, as well as components of equity at the end of the period. This Section applies to interim and annual financial statements relating to fiscal years beginning on or after October 1, 2006. The application of this standard has not had a material impact on the Trust’s financial statements.

Accounting changes

In 2006, the CICA released Section 1506 “Accounting Changes” which establishes criteria for changing accounting policies. Under the new section, voluntary changes in accounting policy are only made if they result in the financial statements providing reliable and more relevant information. Changes in accounting policy are applied retroactively unless it is impracticable to do so or the change in accounting policy is made on initial application of a primary source of GAAP, and that primary source of GAAP has specific transitional provisions. All material prior period errors are to be corrected retroactively. This section is effective for interim and annual financial statements for fiscal years beginning on or after January 1, 2007. The application of this standard has not had a material impact on the Trust’s financial statements.

For recent accounting pronouncements, see note 3 to consolidated financial statements.

Business risks

The trust industry is subject to risks that can affect the amount of funds flow from operations available for distribution to unitholders, and the ability to grow. These risks include but are not limited to:

• capital markets risk and the ability to finance future growth; a

• nd the impact of Canadian governmental regulation on Provident, including the effect of the new tax on trust distributions.

The oil and natural gas industry is subject to numerous risks that can affect the amount of cash flow available for distribution to unitholders and the ability to grow. These risks include but are not limited to:

• fluctuations in commodity price, exchange rates and interest rates;

• government and regulatory risk in respect of royalty and income tax regimes;

• operational risks that may affect the quality and recoverability of reserves;

• geological risk associated with accessing and recovering new quantities of reserves;

• transportation risk in respect of the ability to transport oil and natural gas to market;

• marketability of oil and natural gas;

• the ability to attract and retain employees; and

• environmental, health and safety risks.

The midstream industry is also subject to risks that can affect the amount of cash flow available for distribution to unitholders and the ability to grow. These risks include but are not limited to:

• operational matters and hazards including the breakdown or failure of equipment, information systems or processes, the performance of equipment at levels below those originally intended, operator error, labour disputes, disputes with owners of interconnected facilities and carriers and catastrophic events such as natural disasters, fires, explosions, fractures, acts of eco-terrorists and saboteurs, and other similar events, many of which are beyond the control of the Trust or Provident;

• the Midstream NGL assets are subject to competition from other gas processing plants, and the pipelines and storage, terminal and processing facilities are also subject to competition from other pipelines and storage, terminal and processing facilities in the areas they serve, and the gas products marketing business is subject to competition from other marketing firms;

• exposure to commodity price fluctuations;

• the ability to attract and retain employees;

• regulatory intervention in determining processing fees and tariffs; and

• reliance on significant customers.

Provident strives to minimize these business risks by:

• employing and empowering management and technical staff with extensive industry experience and providing competitive remuneration;

• adhering to a strategy of acquiring, developing and optimizing quality, low-risk reserves in areas where we have technical and operational expertise;

• developing a diversified, balanced asset portfolio that generally offers developed operational infrastructure, year-round access and close proximity to markets;

• adhering to a disciplined Commodity Price Risk Management Program to mitigate the impact that volatile commodity prices have on cash flow available for distribution;

• marketing crude oil and natural gas to a diverse group of customers, including aggregators, industrial users, well-capitalized third-party marketers and spot market buyers;

• marketing natural gas liquids and related services to selected, credit worthy customers at competitive rates;

• maintaining a competitive cost structure to maximize cash flow and profitability;

• maintaining prudent financial leverage and developing strong relationships with the investment community and capital providers;

• adhering to strict guidelines and reporting requirements with respect to environmental, health and safety practices;

• and maintaining an adequate level of property, casualty, comprehensive and directors’ and officers’ insurance coverage.

Unit trading activity

The following table summarizes the unit trading activity of the Provident units for each of the four quarters in the year ended December 31, 2007 on both the Toronto Stock Exchange and the New York Stock Exchange:

		Q1		Q2		Q3		Q4
TSE – PVE.UN (Cdn$)
High	$	13.02	$	13.57	$	12.99	$	12.70
Low	$	11.63	$	12.38	$	11.02	$	9.60
Close	$	12.50	$	12.52	$	12.64	$	9.98
Volume (000s)		16,531		29,522		35,898		36,302
NYSE – PVX (US$)
High	$	11.24	$	12.20	$	12.73	$	13.55
Low	$	9.97	$	10.76	$	10.00	$	9.65
Close	$	10.83	$	11.89	$	12.69	$	10.00
Volume (000s)		54,407		61,559		57,885		75,057

Forward-looking Statements

This MD&A contains forward-looking information or forward-looking statements under applicable securities legislation. These statements relate to future events or the Trust's future performance. Such forward-looking statements or information are provided for the purpose of providing information about management's current expectations and plans relating to the future. Readers are cautioned that reliance on such information may not be appropriate for other purposes, such as making investment decisions. All statements other than statements of historical fact are forward-looking statements. In some cases, forward-looking statements can be identified by terminology such as "may", "will", "should", "expect", "plan", "anticipate", "believe", "estimate", "predict", "potential", "continue", or the negative of these terms or other comparable terminology. Statements relating to "reserves" or "resources" are deemed to be forward-looking statements, as they involve the implied assessment, based on certain estimates and assumptions, that the resources and reserves described can be profitably produced in the future. Forward looking statements or information in this MD&A include, but are not limited to, business strategy and objectives, reserve quantities and the discounted present value of future net cash flows from such reserves, net revenue, future production levels, capital expenditures, exploration plans, development plans, acquisition and disposition plans and the timing thereof, operating and other costs, royalty rates, budgeted levels of cash distributions and the performance associated with Provident's natural gas midstream, NGL processing and marketing business. Forward-looking statements or information are based on current expectations, estimates and projections that involve a number of risks and uncertainties which could cause actual events or results to differ materially from those anticipated by the Trust and described in the forward-looking statements or information. In addition, this MD&A may contain forward-looking statements attributed to third party industry sources. Undue reliance should not be placed on forward-looking statements or information, as there can be no assurance that the plans, intentions or expectations upon which they are based will occur. By its nature, forward-looking information involves numerous assumptions, known and unknown risks and uncertainties, both general and specific, that contribute to the possibility that the predictions, forecasts, projections and other forward-looking statements will not occur. Forward-looking statements in this MD&A include, but are not limited to, statements with respect to:

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

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

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

• the emergence of accretive growth opportunities;

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

• the impact of Canadian governmental regulation on the Trust;

• 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.

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

• industry conditions associated with the NGL services, processing and marketing business;

• fluctuations in the price of crude oil, natural gas and natural gas liquids;

• uncertainties associated with estimating reserves;

• royalties payable in respect of oil and gas production;

• interest payable on notes issued in connection with acquisitions;

• income tax legislation relating to income trusts, including the effect of new legislation taxing trust income;

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

• fluctuation in foreign exchange or interest rates;

• stock market volatility and market valuations;

• the impact of environmental events;

• the need to obtain required approvals from regulatory authorities;

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

• failure to realize the anticipated benefits of acquisitions;

• competition for, among other things, capital reserves, undeveloped lands and skilled personnel;

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

• risks associated with foreign ownership;

• third party performance of obligations under contractual arrangements;

• and the other factors set forth under "Business risks" in this MD&A.

Readers are cautioned that the foregoing list is not exhaustive of all possible risks and uncertainties. With respect to forwarding looking statements and forward looking information contained in this MD&A, the Trust has made assumptions regarding, among other things:

• future natural gas and crude oil prices;

• the ability of the Trust to obtain qualified staff and equipment in a timely and cost-efficient manner to meet demand;

• the regulatory framework regarding royalties, taxes and environmental matters in which the Trust conducts its business;

• the impact of increasing competition; and

• the Trust's ability to obtain financing on acceptable terms.

• the general stability of the economic and political environment in which the Trust operates;

• the timely receipt of any required regulatory approvals;

• the ability of the operator of the projects which the Trust has an interest in to operate the field in a safe, efficient and effective manner;

• field production rates and decline rates;

• the ability to replace and expand oil and natural gas reserves through acquisition, development of exploration;

• the timing and costs of pipeline, storage and facility construction and expansion and the ability of the Trust to secure adequate product transportation;

• currency, exchange and interest rates; and

• the ability of the Trust to successfully market its oil and natural gas products.

Readers are cautioned that the foregoing list is not exhaustive of all factors and assumptions which have been used. The forward-looking statements or information contained in this MD&A are made as of the date hereof and the Trust undertakes no obligation to update publicly or revise any forward-looking statements or information, whether as a result of new information, future events or otherwise unless required by applicable securities laws. The forward looking statements or information contained in this MD&A are expressly qualified by this cautionary statement.

Additional information

Additional information concerning Provident can be accessed under Provident’s public filings at www.sedar.com and www.sec.gov/edgar.shtml, as well as on Provident’s website at www.providentenergy.com.

Selected annual financial measures
($ 000s except per unit data)	2007		2006		2005
Revenue (net of royalties and financial derivative instruments)	$	2,167,276	$	2,187,253	$	1,360,274
Net income		30,434		140,920		96,926
Net income per unit - basic and diluted		0.13		0.72		0.61
Total assets		5,758,792		3,370,919		2,792,270
Long-term financial liabilities (1)		1,863,512		1,098,040		930,756
Declared distributions per unit.	$	1.44	$	1.44	$	1.44
(1) Includes l ong-term debt, asset retirement obligation, long-term financial derivative instruments and other long-term liabilities.

Quarterly table
Segmented information by quarter
($ 000s except for per unit and operating amounts)							2007
	First			Second			Third			Fourth			Year-to-
	Quarter (1)			Quarter (1)			Quarter			Quarter			Date
Financial - consolidated
Revenue	$	587,675		$	504,468		$	533,249		$	541,884		$	2,167,276
Funds flow from operations	$	87,040		$	98,503		$	105,149		$	177,563		$	468,255
Net income (loss)	$	43,093		$	(46,199	)	$	(35,005	)	$	68,545		$	30,434
Net income (loss) per unit - basic and diluted	$	0.20		$	(0.21	)	$	(0.14	)	$	0.28		$	0.13
Unitholder distributions	$	76,271		$	80,236		$	87,782		$	89,063		$	333,352
Distributions per unit	$	0.36		$	0.36		$	0.36		$	0.36		$	1.44
Oil and gas production
Cash revenue	$	125,777		$	139,453		$	155,541		$	186,891		$	607,662
Earnings before interest, DD&A, taxes	$	54,736		$	75,783		$	82,523		$	106,379		$	319,421
and other non-cash items
Funds flow from operations	$	47,636		$	68,934		$	72,799		$	100,454		$	289,823
Net (loss) income	$	(8,745	)	$	95,992		$	(26,375	)	$	130,582		$	191,454
Midstream services and marketing
Cash revenue	$	453,272		$	397,713		$	433,950		$	598,963		$	1,883,898
Earnings before interest, DD&A, taxes	$	52,853		$	35,974		$	47,425		$	89,423		$	225,675
and other non-cash items
Funds flow from operations	$	39,404		$	29,569		$	32,350		$	77,109		$	178,432
Net income (loss)	$	51,838		$	(142,191	)	$	(8,630	)	$	(62,037	)	$	(161,020	)
Operating
Oil and gas production
Light/medium oil (bpd)		14,071			15,557			19,289			20,721			17,433
Heavy oil (bpd)		1,669			1,918			2,324			1,769			1,921
Natural gas liquids (bpd)		1,444			1,344			1,281			1,612			1,421
Natural gas (mcfd)		91,432			96,449			95,588			144,678			107,151
Oil equivalent (boed)		32,423			34,893			38,825			48,215			38,633
Average selling price net of transportation expense
Light/medium oil per bbl	$	57.21		$	59.44		$	64.59		$	69.70		$	63.48
(before realized financial derivative instruments)
Light/medium oil per bbl	$	59.93		$	59.39		$	61.37		$	62.34		$	60.93
(including realized financial derivative instruments)
Heavy oil per bbl	$	34.69		$	42.32		$	45.34		$	43.36		$	41.85
(before realized financial derivative instruments)
Heavy oil per bbl	$	34.69		$	42.32		$	45.34		$	43.36		$	41.85
(including realized financial derivative instruments)
Natural gas liquids per barrel	$	48.86		$	52.56		$	55.22		$	51.39		$	51.90
Natural gas per mcf	$	7.48		$	7.25		$	4.95		$	6.53		$	6.53
(before realized financial derivative instruments)
Natural gas per mcf	$	7.37		$	7.18		$	5.62		$	6.92		$	6.78
(including realized financial derivative instruments)
Midstream
Midstream NGL sales volumes (bpd)		125,033			109,713			112,386			135,981			120,785
(1) Restated - see note 3 to third quarter 2007 interim consolidated financial statements.

Quarterly table
Segmented information by quarter
($ 000s except for per unit and operating amounts)							2006
	First			Second			Third		Fourth			Annual
	Quarter			Quarter			Quarter		Quarter			Total
Financial - consolidated
Revenue	$	553,706		$	424,439		$	661,022	$	548,086		$	2,187,253
Funds flow from operations	$	78,906		$	110,990		$	120,089	$	122,679		$	432,664
Net income (loss)	$	24,200		$	21,371		$	120,850	$	(25,501	)	$	140,920
Net income (loss) per unit - basic	$	0.13		$	0.11		$	0.61	$	(0.12	)	$	0.72
Net income (loss) per unit - diluted	$	0.13		$	0.11		$	0.58	$	(0.12	)	$	0.72
Unitholder distributions	$	68,350		$	68,572		$	70,970	$	75,573		$	283,465
Distributions per unit	$	0.36		$	0.36		$	0.36	$	0.36		$	1.44
Oil and gas production
Cash revenue	$	114,020		$	125,744		$	116,682	$	125,135		$	481,581
Earnings before interest, DD&A, taxes	$	64,313		$	77,698		$	67,750	$	66,497		$	276,258
and other non-cash items
Funds flow from operations	$	52,813		$	71,867		$	61,471	$	62,147		$	248,298
Net income (loss)	$	36,484		$	25,980		$	38,117	$	(14,530	)	$	86,051
Midstream services and marketing
Cash revenue	$	474,515		$	367,624		$	459,603	$	447,244		$	1,748,986
Earnings before interest, DD&A, taxes	$	32,813		$	46,438		$	65,958	$	74,422		$	219,631
and other non-cash items
Funds flow from operations	$	26,093		$	39,123		$	58,618	$	60,532		$	184,366
Net income (loss)	$	(12,284	)	$	(4,609	)	$	82,733	$	(10,971	)	$	54,869
Operating
Oil and gas production
Light/medium oil (bpd)		14,541			13,923			13,955		13,899			14,114
Heavy oil (bpd)		2,506			2,011			2,004		1,838			2,057
Natural gas liquids (bpd)		1,527			1,475			1,326		1,345			1,419
Natural gas (mcfd)		78,274			80,084			80,991		100,029			84,891
Oil equivalent (boed)		31,620			30,756			30,784		33,753			31,739
Average selling price net of transportation expense
Light/medium oil per bbl	$	54.80		$	69.76		$	62.95	$	54.59		$	60.32
(before realized financial derivative instruments)
Light/medium oil per bbl	$	53.40		$	68.00		$	60.72	$	55.56		$	59.22
(including realized financial derivative instruments)
Heavy oil per bbl	$	22.87		$	50.42		$	48.15	$	25.82		$	36.80
(before realized financial derivative instruments)
Heavy oil per bbl	$	22.82		$	50.42		$	48.15	$	25.82		$	36.78
(including realized financial derivative instruments)
Natural gas liquids per barrel	$	53.91		$	54.20		$	52.03	$	47.49		$	51.98
Natural gas per mcf	$	8.00		$	6.10		$	5.88	$	6.71		$	6.66
(before realized financial derivative instruments)
Natural gas per mcf	$	7.85		$	6.41		$	6.24	$	7.12		$	6.91
(including realized financial derivative instruments)
Midstream
Midstream NGL sales volumes (bpd)		130,735			100,284			114,839		115,727			115,354

MANAGEMENT’S REPORT ON INTERNAL CONTROL OVER FINANCIAL REPORTING

The management of Provident is responsible for establishing and maintaining adequate internal control over financial reporting for the Trust. Under the supervision of our Chief Executive Officer and our Chief Financial Officer we have conducted an evaluation of the effectiveness of our internal control over financial reporting based on the Internal Control-Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). Based on our assessment, we have concluded that as of December 31, 2007, our internal control over financial reporting was effective.

Management excluded from its assessment of the effectiveness of the Trust’s internal control over financial reporting certain assets acquired from Quicksilver Resources, Inc. because they were acquired by a subsidiary of the Trust in a purchase business combination during 2007 (as further described in note 4 of the Trust’s consolidated financial statements). Such total assets and total revenues represent approximately 26 percent and less than one percent respectively, of the related consolidated financial statement amounts as of and for the year ended December 31, 2007.

Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

The effectiveness of the Trust’s internal control over financial reporting as of December 31, 2007, has been audited by PricewaterhouseCoopers LLP, independent auditors, as stated in their report which appears herein.


“signed”	“signed”
Thomas W. Buchanan	Mark N. Walker
Chief Executive Officer	Chief Financial Officer

Calgary, Alberta
March 18, 2008

MANAGEMENT’S RESPONSIBILITY FOR FINANCIAL STATEMENTS

The management of Provident is responsible for the information included in this Annual Report. The financial statements have been prepared in accordance with accounting principles generally accepted in Canada and in accordance with accounting policies detailed in the notes to the financial statements. Where necessary, the statements include amounts based on management’s informed judgments and estimates. Financial information in the Annual Report is consistent with that presented in the financial statements.

PricewaterhouseCoopers LLP, Chartered Accountants, appointed by the unitholders, have audited the financial statements and conducted a review of internal accounting policies and procedures to the extent required by generally accepted auditing standards, and performed such tests as they deemed necessary to enable them to express an opinion on the financial statements.

The Board of Directors, through its Audit Committee, is responsible for ensuring that management fulfills its responsibility for financial reporting and internal control. The Audit Committee is composed of three independent directors. The Audit Committee reviews the financial content of the Annual Report and reports its findings to the Board of Directors for its consideration in approving the financial statements.


“signed”	“signed”
Thomas W. Buchanan	Mark N. Walker
Chief Executive Officer	Chief Financial Officer
Calgary, Alberta
March 18, 2008

PROVIDENT ENERGY TRUST
CONSOLIDATED BALAN CE SHEETS
Canadian dollars (000s)

	As at			As at
	December 31,			Decem ber 31,
	2007			2006
Assets
Cur rent assets
Cash and cash equival ents	$	6,820		$	10,302
Account s r eceivable		417,562			270,135
Petroleum pr oduct inventor y		90,274			85,868
Prepaid expenses and other cur r ent assets		9,018			16,381
Financial der ivative instr um ents (note 13)		2,289			12,909
		525,963			395,595
Invest m ent s		21,154			4,320
Defer r ed f inancing char ges		-			12,351
Long- term f inancial der ivat ive inst r um ents (not e 13)		-			171
Pr oper ty, plant and equipm ent (note 5)		4,518,820			2,333,537
Intangible assets (note 6)		175,556			193,592
Goodwill (note 4)		517,299			431,353
	$	5,758,792		$	3,370,919
Liabilities
Cur rent liabilities
Account s payable and accr ued liabilit ies	$	424,468		$	295,003
Cash dist r ibutions payable		25,100			21,506
Distr ibutions payable to non- contr olling int er ests		-			677
Curr ent por tion of convert ible debent ures (note 7)		19,198			-
Financial der ivative instr um ents (note 13)		167,713			22,602
		636,479			339,788
Long- term debt - revolvingterm credit facilities (note 7)		1,292,832			702,993
Long- term debt - convertible debentures (note 7)		256,440			285,792
Asset ret ir ementobl igation (note 8)		80,900			49,614
Long- term f inancial derivative instruments (not e 13)		212,581			43,336
Ot her long- term liabilities (note 11)		20,759			16,305
Fut ur e income taxes (note 12)		450,000			309,006
N on- contr olling interests (not e 9)
USOGP operations		1,100,136			81,111
Subsequent event (note 16)
Unitholders’ equity
Unit holders’ contr ibut ions (note 10)		2,750,374			2,254,048
Convertible debent ures equity com ponent		18,213			18,522
Contributed surplus (not e 11)		801			1,315
Accumulated ot her compr ehensive (loss) incom e		(69,188	)		(42,294	)
Accumulated income		268,642			238,208
Accumulated cashdist ribut ions		(1,260,177	)		(926,825	)
		1,708,665			1,542,974
	$	5,758,792		$	3,370,919

	The accompanying notes to the consolidated financial statements are an integral part of these statements.
On behalf of the Board of Directors:
“signed”		“signed”
M.H. (Mike) Shaikh, FCA		Thomas W. Buchanan, CA
Director		Director

PROVIDENT ENERGY TRUST
CONSOLIDATED STATEMENT OF OPERATIONS AND ACCUMULATED INCOME
Canadian dollars (000s except per unit amounts)

	Year ended
	December 31,
	2007			2006
Revenue
Revenue	$	2,572,265		$	2,244,107
Realized loss on financial derivative instruments		(80,705	)		(13,540	)
Unrealized loss on financial derivative instruments		(324,284	)		(43,314	)
		2,167,276			2,187,253
Expenses
Cost of goods sold		1,605,782			1,471,171
Production, operating and maintenance		208,180			172,253
Transportation		28,120			19,786
Depletion, depreciation and accretion		351,364			249,139
General and administrative (note 11)		114,973			97,288
Interest on bank debt		51,660			34,666
Interest and accretion on convertible debentures		25,347			23,919
Amortization of deferred financing charges		-			3,854
Foreign exchange loss (gain) and other		6,795			(2,319	)
Dilution gain (note 9)		(260,324	)		-
		2,131,897			2,069,757
Income before taxes and non-controlling interests		35,379			117,496
Capital tax expense		3,762			1,314
Current and withholding tax expense		6,362			5,829
Future income tax expense (recovery) (note 12)		30,487			(34,316	)
		40,611			(27,173	)
Net (loss) income before non-controlling interests		(5,232	)		144,669
Non-controlling interests (note 9)
USOGP operations		(35,666	)		2,995
Exchangeable shares		-			754
Net income		30,434			140,920
Accumulated income, beginning of year	$	238,208		$	97,288
Accumulated income, end of year	$	268,642		$	238,208
Net income per unit – basic and diluted	$	0.13		$	0.72

The accompanying notes to the consolidated financial statements are an integral part of these statements.

PROVIDENT ENERGY TRUST
CONSOLIDATED STATEMENT OF CASH FLOWS
Canadian Dollars (000s)
	Year ended
	December 31,
	2007			2006
Cash provided by operating activities
Net income for the year	$	30,434		$	140,920
Add (deduct) non-cash items:
Depletion, depreciation and accretion		351,364			249,139
Non-cash interest expense and other		10,290			6,357
Non-cash unit based compensation (note 11)		14,014			23,083
Unrealized loss on financial derivative instruments		324,284			43,314
Unrealized foreign exchange loss and other		3,372			418
Future income tax expense (recovery) (note 12)		30,487			(34,316	)
Dilution gain (note 9)		(260,324	)		-
Net (loss) income attributable to non-controlling interests		(35,666	)		3,749
Funds flow from operations		468,255			432,664
Site restoration expenditures (note 14)		(4,424	)		(4,622	)
Change in non-cash operating working capital		624			(13,693	)
		464,455			414,349
Cash provided by financing activities
Increase in long-term debt		534,215			117,385
Declared distributions to unitholders		(333,352	)		(283,465	)
Declared distributions to non-controlling interests		(35,846	)		(6,523	)
Issue of trust units, net of issue costs		412,909			257,076
Contributions by non-controlling interests (note 9)		683,100			135,829
Change in non-cash financing working capital		2,179			(154	)
		1,263,205			220,148
Cash used for investing activities
Capital expenditures		(247,122	)		(190,433	)
Capitol Energy acquisition (note 4)		(467,495	)		-
Triwest Energy acquisition (note 4)		(2,300	)		-
USOGP natural gas asset acquisition (note 4)		(763,652	)		-
Acquisition of Midstream NGL business		-			(1,036	)
Oil and gas property acquisitions, net (note 4)		(265,201	)		(481,625	)
Increase in investments		(5,450	)		-
Proceeds on sale of assets		5,030			11,517
Change in reserve for future site reclamation (note 14)		-			1,872
Change in non-cash investing working capital		15,048			3,397
		(1,731,142	)		(656,308	)
Decrease in cash and cash equivalents		(3,482	)		(21,811	)
Cash and cash equivalents beginning of year		10,302			32,113
Cash and cash equivalents end of year	$	6,820		$	10,302
Supplemental disclosure of cash flow information
Cash interest paid including debenture interest	$	69,600		$	56,036
Cash taxes paid	$	13,741		$	9,601

The accompanying notes to the consolidated financial statements are an integral part of these statements.

PROVIDENT ENERGY TRUST
CONSOLIDATED STATEMENT OF COMPREHENSIVE INCOME AND
ACCUMULATED OTHER COMPREHENSIVE INCOME
Canadian Dollars (000s)
	Year ended
	December 31,
	2007			2006

Net income	$	30,434		$	140,920
Other comprehensive (loss) income, net of taxes
Foreign currency translation adjustments		(25,083	)		(509	)
Unrealized loss on available-for-sale investments
(net of taxes of $262)		(1,811	)		-
		(26,894	)		(509	)

Comprehensive income	$	3,540		$	140,411
Accumulated other comprehensive (loss) income, beginning of year		(42,294	)		(41,785	)
Other comprehensive (loss) income		(26,894	)		(509	)
Accumulated other comprehensive (loss) income, end of year	$	(69,188	)	$	(42,294	)
Accumulated income, end of year		268,642			238,208
Accumulated cash disributions, end of year		(1,260,177	)		(926,825	)
Retained earnings (deficit), end of year		(991,535	)		(688,617	)
Total retained earnings (deficit) and accumulated other comprehensive
(loss) income, end of year	$	(1,060,723	)	$	(730,911	)

The accompanying notes to the consolidated financial statements are an integral part of these statements.

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

(Tabular amounts in Cdn$ 000’s, except unit and per unit amounts)

December 31, 2007

1.	Structure of the Trust

Provident Energy Trust (the “Trust”) is an open-end unincorporated investment trust created under the laws of Alberta pursuant to a trust indenture dated January 25, 2001, amended from time to time. The beneficiaries of the Trust are the unitholders. The Trust was established to hold, directly and indirectly, all types of petroleum and natural gas and energy related assets, including without limitation facilities of any kind, oil sands interests, electricity or power generating assets and pipeline, gathering, processing and transportation assets. The Trust commenced operations March 6, 2001.

Cash flow is provided to the Trust from properties owned and operated by Provident Energy Ltd. and directly and indirectly owned subsidiaries of the Trust (“Provident”). Cash flow is paid from Provident to the Trust by way of royalty payments, interest payments and principal debt repayments. The cash payments received by the Trust are subsequently distributed to the unitholders monthly.

2.	Significant accounting policies

i)	Principles of consolidation and investments

The consolidated financial statements include the accounts of the Trust and Provident, including the consolidated accounts of all wholly and partially owned subsidiaries, and are presented in accordance with Canadian generally accepted accounting principles. Investments subject to significant influence are accounted for using the equity method. Certain comparative numbers have been restated to conform to the current year presentation.

ii)	Financial instruments

All financial instruments, including derivatives, are recognized on the Trust’s Consolidated Balance Sheet. Derivatives are measured at fair value with unrealized gains and losses reported in net income. Investments, other than investments accounted for by the equity method, are measured at fair value, with reference to published price quotations, and unrealized gains and losses are reported in AOCI. The Trust’s other financial instruments (accounts receivable, accounts payable, and long-term debt) are measured at amortized cost using the effective interest rate method. Transaction costs are included with the associated financial instruments and amortized accordingly (see note 3).

iii)	Cash and cash equivalents

Cash and cash equivalents include short-term investments, such as money market deposits or similar type instruments, with an original maturity of three months or less when purchased.

iv)	Property, plant & equipment and intangible assets

The Trust follows the full cost method of accounting for oil and natural gas exploration and development activities, whereby all costs associated with the acquisition and development of oil and natural gas reserves are capitalized.

Such costs include lease acquisition, lease rentals on non-producing properties, geological and geophysical activities, drilling of productive and non-productive wells, and tangible well equipment. Gains or losses on the disposition of oil and gas properties are not recognized unless the resulting change to the depletion and depreciation rate is 20 percent or more. All other property, plant and equipment, including midstream assets, are recorded at cost. Expenditures relating to renewals or betterments that improve the productive capacity or extend the life of property, plant and equipment are capitalized. Maintenance and repairs are expensed as incurred. Products required for line-fill and cavern bottoms are presented as part of property, plant and equipment and are stated at the lower of historic cost and net realizable value and are not depreciated.

a)	Depletion, depreciation and accretion

The provision for depletion and depreciation for oil and natural gas assets is calculated, by cost centre, using the unit-of-production method based on current production divided by the Trust’s share of estimated total proved oil and natural gas reserve volumes, before royalties. Production and reserves of natural gas and associated liquids are converted at the energy equivalent ratio of 6,000 cubic feet of natural gas to one barrel of oil. In determining its depletion base, the Trust includes estimated future costs for developing proved reserves, and excludes estimated salvage values of tangible equipment and the cost of unproved properties.

Midstream facilities, including natural gas liquids storage facilities and natural gas liquids processing and extraction facilities are carried at cost and depreciated on a straight-line basis over the estimated service lives of the assets, which range from 30 to 40 years. Intangible assets are amortized over the estimated useful lives of the assets, which range from two to 15 years. Capital assets related to pipelines are carried at cost and depreciated using the straight-line method over their economic lives.

b)	Impairment

Oil and natural gas assets accounted for using the full cost method are subject to a ceiling test. The ceiling test calculation is performed by comparing the carrying value of the cost centre to the sum of the undiscounted proved reserve cash flows expected from the cost centre by country using future price estimates. If the carrying value is not recoverable, the cost centre is written down to its fair value. Fair value is determined by the future cash flows from the proved plus probable reserves discounted at the Trust’s risk free interest rate. Any excess carrying value of the assets on the balance sheet above fair value would be recorded in depletion, depreciation and accretion expense as a permanent impairment.

For Midstream property, plant and equipment, and intangible assets, an impairment loss is recognized when the carrying amount exceeds the fair value.

v)	Joint venture

Provident conducts many of its activities through joint ventures and the accounts reflect only Provident’s proportionate interest in such activities.

vi)

Inventory

Inventories of products are valued at the lower of average cost and net realizable value based on market prices.

vii)

Goodwill

Goodwill, which represents the excess of cost of an acquired enterprise over the net of the amounts assigned to assets acquired and liabilities assumed, is assessed at least annually for impairment. To assess impairment, the fair value of the reporting unit is determined and compared to the book value of the reporting unit. If the fair value is less than the book value, then a second test is performed to determine the amount of the impairment. The amount of the impairment is determined by deducting the fair value of the reporting unit’s assets and liabilities from the fair value of the reporting unit to determine the implied fair value of goodwill and comparing that amount to the book value of the reporting unit’s goodwill. Any excess of the book value of goodwill over the implied fair value of goodwill is the impaired amount. Goodwill is not amortized.

viii)

Asset retirement obligation

Under the asset retirement obligation (“ARO”) standard the fair value of a liability for an ARO is recorded in the period where a reasonable estimate of the fair value can be determined. When the liability is recorded, the carrying amount of the related asset is increased by the same amount of the liability. The asset recorded is depleted over the useful life of the asset. Additions to asset retirement obligations due to the passage of time are recorded as accretion expense. Actual expenditures incurred are charged against the obligation.

ix)	Unit based compensation

The Trust uses the fair value method of valuing compensation expense associated with the Trust’s unit option plan. Provident has applied this method to options issued after January 1, 2003, the effective date for implementing stock based compensation. Under the fair value method the amount to be recognized as expense is determined at the time

the options are issued and is recognized in earnings over the vesting period of the options with a corresponding increase in contributed surplus.

The Trust has established other unit based compensation plans whereby notional units are granted to employees. The fair value of these notional units is estimated and recorded as part of general and administrative expenses with an offsetting amount to accrued liabilities or other long—term liabilities. A realization of the expense and a resulting reduction in cash provided by operating activities occurs when a cash payment is made.

x)	Trust unit calculations

The Trust applies the treasury stock method to determine the dilutive effect of trust unit rights and trust unit options. Under the treasury stock method, outstanding and exercisable instruments that will have a dilutive effect are included in per unit - diluted calculations, ordered from most dilutive to least dilutive.

The dilutive effect of convertible debentures is determined using the "if-converted" method whereby the outstanding debentures at the end of the period are assumed to have been converted at the beginning of the period or at the time of issue if issued during the year. Amounts charged to income or loss relating to the outstanding debentures are added back to net income for the diluted calculation. The units issued upon conversion are included in the denominator of per unit - basic calculations from the date of issue.

xi)	Income taxes

Provident follows the liability method for calculating income taxes. Differences between the amounts reported in the financial statements of the corporate subsidiaries and their respective tax bases are applied to tax rates in effect to calculate the future tax liability. The effect of any change in income tax rates is recognized in the current period income.

The Trust is a taxable entity under the Income Tax Act (Canada) and is currently taxable only on income that is not distributed or distributable to the unitholders. As the Trust distributes all of its taxable income to the unitholders and meets the requirements of the Income Tax Act (Canada) applicable to the Trust, no provision for current income taxes has been made in the Trust.

In 2007, the Canadian government enacted Bill C-52, Budget Implementation Act 2007. This bill contains legislation to tax publicly traded trusts, commencing in 2011. As a result of this legislation, the Trust records the future income tax effect of the temporary differences on its flow through entities that are expected to reverse subsequent to 2010.

xii)	Revenue recognition

Revenue associated with the sales of Provident’s natural gas, natural gas liquids (“NGLs”) and crude oil owned by Provident is recognized when title passes from Provident to its customer.

Marketing revenues and purchased product are recorded on a gross basis when Provident takes title to product and has the risks and rewards of ownership.

Revenues associated with the services provided where Provident acts as agent are recorded on a net basis when the services are provided. Revenues associated with the sale of natural gas liquids storage services are recognized when the services are provided.

xiii)

Foreign currency translation

The accounts of self-sustaining foreign operations are translated using the current rate method, whereby assets and liabilities are translated at period-end exchange rates, while revenue and expenses are translated using average rates for the period. Translation gains and losses related to self-sustaining operations are deferred and included as a component of accumulated other comprehensive income. A proportionate amount of the gain or loss is recognized in net income when there has been a reduction in the net investment.

The accounts of integrated foreign operations are translated using the temporal method, under which monetary assets and liabilities are translated at the period-end exchange rate, other assets and liabilities at the historical rates, and revenues and expenses at the rates for the period, except depreciation, depletion and accretion which is translated on the same basis as the related assets. Translation gains and losses are included in income in the period in which they arise.

xiv)	Use of estimates

The preparation of financial statements requires management to make estimates based on currently available information. Actual results could differ from those estimated. In particular, management makes estimates for amounts recorded for depletion and depreciation of the property, plant and equipment, asset retirement obligation and future income taxes. The ceiling test uses factors such as estimated reserves, production rates, estimated future petroleum and natural gas prices and future costs. Due to the inherent limitations in metering and the physical properties of storage caverns and pipelines, the determination of precise volumes of natural gas liquids held in inventory at such locations is subject to estimation. Actual inventories of natural gas liquids can only be determined by draining of the caverns. By their very nature, these estimates are subject to measurement uncertainty and the effect on the financial statements of future periods could be material.

The estimation of oil and gas reserves is a subjective process. Forecasts are based on engineering data, projected future rates of production, estimated commodity prices, and the timing of future expenditures. The Trust expects reserve estimates to be revised based on the results of future drilling activity, testing, production levels, and economics of recovery based on cash flow forecasts.

3.	Changes in accounting policies and practices

A.	Changes in accounting policies

i) Financial instruments

Effective January 1, 2007, the Trust adopted the requirements of the Canadian Institute of Chartered Accountants (“CICA”) related to the new financial instruments accounting framework, which encompasses the following new CICA Handbook sections: 3855 Financial Instruments – Recognition and Measurement, 1530 Comprehensive Income, and 3861 Financial Instruments – Disclosure and Presentation. The CICA Handbook section 3865 Hedges is effective January 1, 2007, however, the Trust has elected not to apply hedge accounting, consistent with prior periods.

In conjunction with the above standards, the CICA issued Section 3862 “Financial Instruments-Disclosures” and Section 3863 “Financial Instruments-Presentation”. Section 3862 requires entities to provide disclosures in their financial statements that enable users to evaluate the significance of financial instruments to the entity’s financial position and performance. It also requires that entities disclose the nature and extent of risks arising from financial instruments and how the entity manages those risks. Section 3863 establishes presentation guidelines for financial instruments and non-financial derivatives and addresses the classification of financial instruments, from the perspective of the issuer, between liabilities and equity, the classification of related interest, dividends, losses and gains, and circumstances in which financial assets and financial liabilities are offset. These two sections are effective for annual and interim periods relating to fiscal years beginning on or after October 1, 2007. The Trust is currently evaluating the effect that these standards might have on the consolidated financial statements.

Several adjustments in the Trust’s consolidated financial statements were required upon transition to the new financial instruments framework, which were the following:

Long-term debt and deferred financing charges

Comprehensive income

ii)

Equity

In 2005, the CICA issued Section 3251 “Equity”. This Section replaces Section 3250 “Surplus” and establishes standards for the presentation of equity and changes in equity during the reporting period. The Section requires an entity to present separately each of the changes in equity during the period, including comprehensive income, as well as components of equity at the end of the period. This Section applies to interim and annual financial statements relating to fiscal years beginning on or after October 1, 2006. The application of this standard has not had a material impact on the Trust’s financial statements.

iii)	Accounting changes

B.	Recent accounting pronouncements

Inventory

In June 2007, the CICA issued a new accounting standard, Section 3031 - Inventories, which replaces the existing standard for inventories, Section 3030. The main features of the new Section are as follows:

•	measurement of inventories at the lower of cost and net realizable value;

•	consistent use of either first-in, first-out or a weighted average cost formula to measure cost;

•	reversal of previous write-downs to net realizable value when there is a subsequent increase to the value of inventories.

The new Section is effective for the Trust beginning January 1, 2008. The Trust is currently evaluating the effect that this standard might have on the consolidated financial statements.

ii)	Capital disclosures

In 2006, the CICA released Section 1535 “Capital Disclosures” which addresses the requirements for an entity to disclose qualitative information about its objectives, policies and processes for managing capital. This section also establishes the requirement for an entity to disclose quantitative data about what it regards as capital as well as disclose whether it has complied with any externally imposed capital requirements and, if not, the consequences of such non-compliance. This section is effective for interim and annual financial statements relating to fiscal years beginning on or after October 1, 2007. The Trust is currently evaluating the effect that this standard might have on the consolidated financial statements.

iii)	Goodwill and intangible assets

In February 2008, the CICA released section 3064 “Goodwill and intangible assets” which supersedes section 3062 “Goodwill and other intangible assets” and section 3450 “Research and development.” This new section establishes standards for the recognition, measurement and disclosure of goodwill and intangible assets. This section applies to annual and interim financial statements relating to fiscal years beginning on or after October 1, 2008. The Trust does not expect the adoption of this standard to have a material impact on its financial statements.

4.	Acquisitions

i)	Acquisition of Triwest

On December 3, 2007, the Trust acquired the common shares of Triwest Energy Inc. (“Triwest”), for consideration of 6,251,149 trust units with an ascribed value of $76.6 million plus acquisition costs of $0.8 million and cash consideration of $1.5 million. Triwest was a privately held company with oil assets primarily in southeast Saskatchewan. The transaction was accounted for using the purchase method with the allocation of the purchase price as follows:

Net assets acquired and liabilities assumed
Property, plant and equipment	$	115,719
Working capital, net		(2,757	)
Bank debt		(11,122	)
Asset retirement obligation		(752	)
Future income taxes		(22,211	)
	$	78,877
Consideration
Acquisition costs	$	800
Cash		1,500
		2,300
Trust units issued		76,577
	$	78,877

ii)	Acquisition of USOGP natural gas assets

On November 1, 2007, BreitBurn Energy Partners L.P. (the “MLP”) completed the acquisition of certain assets from Quicksilver Resources Inc. (“Quicksilver”) in exchange for cash consideration of U.S. $750 million and 21,347,972 MLP units reducing Provident’s ownership in the MLP from approximately 50 percent to approximately 22 percent. The assets acquired include all of Quicksilver’s natural gas, oil and related assets in Michigan, Indiana and Kentucky.

The transaction has been accounted for as an asset purchase with the allocation of cost as follows (in Canadian dollars):

Property, plant and equipment	$	1,453,697
Investments accounted for using the equity method		15,600
Intangible assets		5,131
Working capital, net		15
Asset retirement obligation		(10,230	)
	$	1,464,213
Consideration
Acquisition costs		12,952
Cash	$	750,700
		763,652
MLP units issued to Quicksilver		700,561
	$	1,464,213

The cash portion of the consideration was financed by the issue of 16,666,667 MLP units at U.S. $27.00 per unit (less underwriting fees and other costs of U.S. $8.7 million) and the MLP’s credit facility.

iii)	Acquisition of Capitol

On June 19, 2007, the Trust acquired Capitol Energy Resources Ltd. (“Capitol”) for cash consideration of $467.5 million. Capitol was a public oil and gas exploration and production company active in the Western Canadian sedimentary basin. The transaction has been accounted for using the purchase method with the allocation of the purchase price as follows:

Net assets acquired and liabilities assumed
Property, plant and equipment	$	522,707
Goodwill		85,946
Working capital, net		17,108
Bank debt		(53,100	)
Financial derivative instruments		(621	)
Asset retirement obligation		(1,752	)
Future income taxes		(102,793	)
	$	467,495
Consideration
Acquisition costs	$	1,115
Cash		466,380
	$	467,495

The Capitol acquisition was financed by the issuance of 29,313,727 trust units at $12.75 per unit and Provident’s credit facility.

iv)	MLP acquisitions

In May 2007, BreitBurn Energy Partners L.P. (the “MLP”) completed two oil and gas property acquisitions, one in Florida for cash consideration of U.S. $108.1 million and one in California for cash consideration of U.S. $92.5 million. The transactions were accounted for as asset purchases with the allocation of cost as follows (in Canadian dollars):

Property, plant and equipment	$	205,160
Intangible assets		3,591
Inventory		11,282
Other working capital, net		(821	)
Asset retirement obligation		(4,708	)
	$	214,504

The acquisitions were financed by the issue of units by the MLP to institutional investors (see note 9).

v)	Acquisition of Rainbow assets

On August 31, 2006 Provident acquired a package of natural gas producing assets in the Rainbow and Peace River Arch areas of northwestern Alberta. The transaction was accounted for as an asset purchase with the allocation of the purchase price as follows:

Net assets acquired and liabilities assumed
Property, plant and equipment	$	660,427
Asset retirement obligation		(1,903	)
Future income taxes		(185,726	)
	$	472,798
Consideration
Acquisition costs	$	500
Cash		472,298
	$	472,798

The acquisition was financed by the issuance of 16,325,000 units at $13.85 per unit and Provident’s credit facilities.

Property, plant and equipment

			Accumulated
			depletion and		Net Book
Year ended December 31, 2007	Cost		depreciation		value
Oil and natural gas properties	$	4,977,958	$	1,215,499	$	3,762,459
Midstream assets		790,434		63,763		726,671
Office equipment		40,936		11,246		29,690
Total	$	5,809,328	$	1,290,508	$	4,518,820
			Accumulated
			depletion and		Net Book
Year ended December 31, 2006	Cost		depreciation		value
Oil and natural gas properties	$	2,513,031	$	927,087	$	1,585,944
Midstream assets		781,092		42,143		738,949
Office equipment		17,070		8,426		8,644
Total	$	3,311,193	$	977,656	$	2,333,537

Costs associated with unproved properties and major development projects excluded from costs subject to depletion as at December 31, 2007 totaled $137.7 million (December 31, 2006 - $17.8 million). Midstream assets include $35.9 million (2006 - $22.0 million) for products required for line-fill and cavern bottoms.

An impairment test calculation was performed on property, plant and equipment at December 31, 2007 in which the estimated undiscounted future net cash flows based on estimated future prices associated with the proved reserves exceeded the carrying amount of oil and gas property, plant and equipment for each cost centre.

The following table outlines prices used in the impairment test at December 31, 2007:

	Oil			Gas			NGL
Year	$ /bbl			$ /mcf			$/bbl
2008	$	60.10		$	6.80		$	63.71
2009	$	59.38		$	7.60		$	62.00
2010	$	59.24		$	7.87		$	60.98
2011	$	58.11		$	8.11		$	59.39
2012	$	58.55		$	8.37		$	59.91
Thereafter (1)		2.00	%		2.00	%		2.00	%

(1) Percentage change represents the increase in each year after 2012 to the end of the reserve life.

Intangible assets

			Accumulated			Net Book
December 31, 2007	Cost		amortization			value
Midstream contracts and customer relationships	$	183,100		$	25,049	$	158,051
Fractionation spread support agreement - Midstream		17,600			17,600		-
Other intangible assets - Midstream		16,308			2,566		13,742
U.S. oil and natural gas production related intangible assets		8,468			4,705		3,763
Total	$	225,476		$	49,920	$	175,556

			Accumulated			Net Book
December 31, 2006	Cost		amortization			value
Midstream contracts and customer relationships	$	183,100		$	12,842	$	170,258
Fractionation spread support agreement - Midstream		17,600			9,258		8,342
Other intangible assets - Midstream		16,308			1,316		14,992
Total	$	217,008		$	23,416	$	193,592

Long-term debt

	December 31, 2007			December 31, 2006
Revolving term credit facilities	$	1,292,832		$	702,993
Convertible debentures		275,638			285,792
Current portion of convertible debentures		(19,198	)		-
		256,440			285,792
Total	$	1,549,272		$	988,785

i)	Revolving term credit facilities

Provident has a $1,125 million term credit facility with a syndicate of Canadian chartered banks secured by midstream assets and by its Canadian oil and gas properties. Provident may draw on the credit facility by way of Canadian prime rate loans, U.S. base rate loans, banker’s acceptances, letters of credit or LIBOR loans. At December 31, 2006 the facility totaled $925 million. In May 2007 the facility was increased to its current level of $1,125 million. At December 31, 2007, $925.3 million was drawn on this facility. Included in the carrying value at December 31, 2007 were financing costs of $1.3 million.

The terms of the credit facility have a revolving three year period expiring on May 30, 2010. Provident can extend the revolving period by an additional year, no earlier than 90 days and no later than 30 days prior to the end of the first year of the applicable three year revolving period. If the lenders do not extend the revolving period, or Provident chooses not to extend, the credit facility will be terminated and the loan balance will become due and payable in full on the maturity date.

At December 31, 2007 the effective interest rate of the outstanding credit facilities was 5.9 percent (2006 – 5.2 percent). At December 31, 2007 Provident had $35.9 million in letters of credit outstanding (2006 - $31.9 million) that guarantee Provident’s performance under certain commercial and other contracts.

ii)	Convertible debentures

The Trust may elect to satisfy interest and principal obligations by the issue of trust units. For the twelve months ended December 31, 2007, $6.1 million of the face value of debentures were converted to trust units at the election of debenture holders (2006 - $15.4 million). Included in the carrying value at December 31, 2007 were financing costs of $7.0 million. The fair value of the convertible debentures at December 31, 2007 approximates the face value of the instruments. The following table details each outstanding convertible debenture.

	As at					As at
Convertible Debentures	December 31, 2007					December 31, 2006
												Conversion
	Carrying					Carrying						Price per
($ 000s except conversion pricing)		Value(1	)	Face Value			Value(1	)	Face Value		Maturity Date		unit(2	)
6.5% Convertible Debentures	$	140,515		$	149,980	$	142,860		$	150,000	April 30, 2011		14.75
6.5% Convertible Debentures		91,460			99,024		93,134			99,024	Aug. 31, 2012		13.75
8.0% Convertible Debentures		24,465			25,109		24,402			25,114	July 31, 2009		12.00
8.75% Convertible Debentures		19,198			19,931		25,396			25,972	Dec. 31, 2008		11.05
	$	275,638		$	294,044	$	285,792		$	300,110

(1) Excluding equity component of convertibl e debentures

(2) The debentures may be converted into trust units at the option of the holder of the debenture at the conversion price per unit

8.	Asset retirement obligation

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

The total undiscounted amount of future cash flows required to settle asset retirement obligations related to oil and gas operations is estimated to be $613.1 million (2006 - $411.6 million). Payments to settle oil and gas asset retirement obligations occur over the operating lives of the assets estimated to be from two to 52 years.

The total undiscounted amount of future cash flows required to settle the midstream asset retirement obligations is estimated to be $166.1 million (2006 - $166.1 million). The estimated costs include such activities as dismantling, demolition and disposal of the facilities as well as remediation and restoration of the surface land. Payments to settle the midstream asset retirement obligations are expected to occur subsequent to the closure of the facilities and related assets. Settlement of these obligations is expected to occur in 29 to 40 years.

	Year ended December 31,
($000s)	2007			2006
Carrying amount, beginning of year	$	49,614		$	41,133
Acquisitions		17,442			1,903
Change in estimate		14,561			6,793
Increase in liabilities incurred during the year		2,547			1,443
Settlement of liabilities during the year		(4,424	)		(4,622	)
Decrease in liabilities due to disposition		(654	)		(946	)
Accretion of liability		4,885			3,822
Foreign currency translation adjustments		(3,071	)		88
Carrying amount, end of year	$	80,900		$	49,614

Non-controlling interests – USOGP

	Year ended December 31,
	2007			2006
Non-controlling interests, beginning of year	$	81,111		$	11,885
Net (loss) income attributable to non-controlling interests		(35,666	)		2,995
Distributions to non-controlling interests		(35,846	)		(6,523	)
Investments by non-controlling interests		1,129,073			72,754
Foreign currency translation adjustment		(38,536	)		-
Non-controlling interests, end of year	$	1,100,136		$	81,111
Accumulated (loss) income attributable to non-controlling interests	$	(30,152	)	$	5,514

In the second quarter of 2006, a USOGP subsidiary began a land development project with a partner. The subsidiary has a 20 percent interest, with the partner holding 80 percent. Because the subsidiary stands to receive a majority share of the future proceeds, Provident is consolidating the results in its statements, with the partner’s interest recorded as non-controlling interest. Contributions by the non-controlling interest total $3.9 million in 2007 (2006 - $3.7 million).

In the fourth quarter of 2006, Provident’s subsidiary, BreitBurn Energy Partners, L.P. (the “MLP”) completed its initial public offering. BreitBurn transferred oil and gas properties comprising approximately half of its proved reserves and two thirds of its daily production to the MLP. The offering of 6.9 million common units at U.S. $18.50 per unit resulted in approximately 34 percent of the MLP held by partners not related to Provident. During the second quarter of 2007, the MLP issued 7.0 million common units to third parties for proceeds of $237.5 million. As a result of this transaction, Provident’s interest in the MLP decreased from approximately 66 percent to approximately 50 percent, resulting in a dilution gain of $98.6 million recorded on the consolidated statement of operations. During the fourth quarter of 2007, the MLP issued 38.0 million units in conjunction with the USOGP natural gas asset acquisition. The cash proceeds and ascribed value of these issued units totaled $1,142.2 million. As a result of this transaction, Provident’s interest in the MLP decreased from approximately 50 percent to approximately 22 percent, resulting in an additional dilution gain of $161.7 million recorded on the consolidated statement of operations. The non-controlling interest balance increased by $1,119.4 million in 2007 reflecting the non-controlling interest ownership change from approximately 34 percent to approximately 78 percent. The Trust, through its 95.6 percent general partnership interest, continues to control and consolidate the MLP.

10. Unitholders’ contributions

The Trust has authorized capital of an unlimited number of common voting trust units.

Trust units are redeemable at any time on demand by the holders thereof. Upon receipt of a redemption request by the Trust, the holder is entitled to receive a price per trust unit (the “Market Redemption Price”) equal to the lesser of: (i) 90 percent of the simple average of the closing price of the trust units on the principal market on which the trust units are quoted for trading during the 10 trading day period commencing immediately after the date on which the trust units are surrendered for redemption; and (ii) the closing market price on the principal market on which the trust units are quoted for trading on the date that the trust units are surrendered for redemption.

The aggregate Market Redemption Price payable by the Trust in respect of any trust units surrendered for redemption during any calendar month shall be satisfied by way of a cash payment on the last day of the following month. Total cash payments for redemption are limited to an annual maximum of $250,000. Any excess over the maximum may be satisfied by distributing notes having an aggregate principal amount equal to the aggregate Market Redemption Price of the trust units tendered for redemption.

i) 2007 activity

On December 3, 2007 the Trust issued 6.3 million units (at an ascribed value of $76.6 million) as part of the consideration to acquire the outstanding shares of Triwest Energy Inc.

In 2007, the Trust issued 5.8 million units related to Provident’s DRIP program, conversion of convertible debentures to units and units issued pursuant to Provident’s Unit Option Plan. The net increase in unitholders’ contributions associated with these activities was $65.2 million.

ii) 2006 activity

On July 31, 2006 the Trust issued 16,325,000 Subscription Receipts at a price of $13.85 per Subscription Receipt for total proceeds of $226.1 million ($214.2 million net of issue costs). Each Subscription Receipt entitled the holder to receive one trust unit upon completion of the Rainbow asset acquisition. The acquisition closed on August 31, 2006 at which time all the outstanding Subscription Receipts were converted into trust units. At that time, the holders of the Subscription Receipts were also entitled to $0.12 per trust unit, which is the equivalent of the August distribution paid in September. This payment was treated as a reduction to the proceeds received for the units issued through the Subscription Receipts to $13.73 per trust unit, reducing the amount attributed to Unitholders’ contributions by $2.0 million. Proceeds from the issue were used to fund the Rainbow asset acquisition.

In 2006, the Trust issued 6.1 million units related to Provident’s DRIP program, conversion of exchangeable shares to units, conversion of convertible debentures to units and units issued pursuant to Provident’s Unit Option Plan. The net increase in unitholders’ contributions associated with these activities was $70.1 million.

			Year ended December 31,
	2007					2006
			Amount			Number of		Amount
Trust Units	Number of units			(000s	)	units			(000s	)
Balance at beginning of year		211,228,407	$	2,254,048			188,772,788	$	1,971,707
Issued for cash		29,313,727		373,750			16,325,000		224,142
Issued to acquire Triwest Energy Inc.		6,251,149		76,577			-		-
Exchangeable share conversions		-		-			881,083		9,012
Issued pursuant to unit option plan		825,349		8,426			907,201		8,589
Issued pursuant to the distribution reinvestment plan		3,941,864		45,338			2,714,636		33,045
To be issued pursuant to the distribution reinvestment plan		525,822		5,153			300,134		3,806
Debenture conversions		548,455		6,270			1,327,565		15,689
Unit issue costs		-		(19,188	)		-		(11,942	)
Balance at end of year		252,634,773	$	2,750,374			211,228,407	$	2,254,048

The basic per trust unit amounts for 2007 were calculated based on the weighted average number of units outstanding of 229,939,158 (2006 – 196,627,060). The diluted per trust unit amounts for 2007 are calculated including no additional trust units (2006 – 286,957) for the dilutive effect of the unit option plan and the convertible debentures.

11.	Unit based compensation

i)	Restricted/Performance units

Certain employees of the Trust’s Canadian and U.S. subsidiaries are granted restricted trust units (RTUs) and/or performance trust units (PTUs), both of which entitle the employee to receive cash compensation in relation to the value of a specific number of underlying notional trust or U.S. subsidiary units. The grants are based on criteria designed to recognize the long term value of the employee to the organization. RTUs vest evenly over a period of three years commencing at the grant date. Payments are made on the anniversary dates of the RTU to the employees entitled to receive them on the basis of a cash payment equal to the value of the underlying notional units. PTUs vest three years from the date of grant and can be increased to a maximum of double the PTUs granted or a minimum of nil PTUs depending on the Trust’s performance vis-à-vis other trusts’ performance based on certain benchmarks.

As of December 31, 2007 there were 1,408,196 RTUs and 4,441,152 PTUs outstanding (2006 – 571,423 RTUs and 1,704,234 PTUs). The fair value estimate associated with the RTUs and PTUs is expensed in the statement of operations over the vesting period. At December 31, 2007, $12.7 million (2006 - $2.3 million) is included in accounts payable and accrued liabilities for this plan and $14.8 million (2006 - $13.3 million) is included in other long-term liabilities. The following table reconciles the expense recorded for RTUs and PTUs.

	Year ended December 31,
	2007		2006
Cash general and administrative	$	2,395	$	1,021

Non-cash unit based compensation (included in general and administrative)		11,576		11,156
Production, operating and maintenance expense		1,247		939
	$	15,218	$	13,116

ii)	Unit option plan

The Trust option plan (the “Plan”) is administered by the Board of Directors of Provident. In October 2005, a restricted/performance unit program (see (i)) was approved. This program replaces the unit option plan. Unit options in existence will continue to be outstanding.

At December 31, 2007, the Trust had 1,279,169 options outstanding and exercisable with strike prices ranging between $10.49 and $12.14 per unit. The weighted average remaining contractual life of the options was 0.87 years and the weighted average exercise price was $11.04 per unit excluding average potential reductions to the strike prices of $1.77 per unit.

At December 31, 2006, the Trust had 2,114,808 options outstanding with strike prices ranging between $10.49 and $12.14 per unit. The weighted average remaining contractual life of the options was 1.96 years and the weighted average exercise price was $11.09 per unit excluding average potential reductions to the strike prices of $1.50 per unit. Of these outstanding options, 1,947,989 were exercisable with a weighted average price of $11.08.

The following table reconciles the movement in the contributed surplus balance.

	Year ended December 31,
	2007			2006
Contributed surplus, beginning of the year	$	1,315		$	1,675

Non-cash unit based compensation (included in general and administrative)		57			203
Benefit on options exercised charged to unitholders’ equity		(571	)		(563	)
Contributed surplus, end of year	$	801		$	1,315

iii)	Unit appreciation rights

At December 31, 2007, the Trust’s U.S. subsidiaries had unit appreciation rights (UARs) outstanding of 187,656 (2006 – 472,521) with a weighted average price of U.S. $9.58 (2006 – U.S. $8.41). Of these outstanding UARs, 148,336 (2006 – 81,852) were exercisable at a weighted average price of U.S. $9.46 (2006 – U.S. $8.46).

The fair value associated with the UARs is expensed in the statement of operations over the vesting period. At December 31, 2007, $0.8 million (2006 - $2.5 million) is included in accounts payable and accrued liabilities for this plan and nil (2006 - $0.1 million) is included in other long-term liabilities. The following table reconciles the expense recorded for UARs

	Year ended December 31,
	2007			2006
Cash general and administrative	$	2,113		$	798
Non-cash unit based compensation
(included in general and administrative)		(1,490	)		1,246
	$	623		$	2,044

iv)	Other unit based compensation

Pursuant to employment agreements between the Trust’s U.S. subsidiaries and certain employees, the employees are eligible to receive cash compensation in relation to the value of a specified number of underlying notional units.

The value of each notional unit is determined on the basis of a valuation of the U.S. subsidiaries as at the end of the fiscal period. At December 31, 2007 there were 3,061,137 notional units outstanding under the key employee plan (2006 – 2,755,566). There were 2,965,502 notional units outstanding under other USOGP unit based plans (2006 – 12,984,001). At December 31, 2007, $8.7 million (2006 - $13.4 million) is included in accounts payable and accrued liabilities for these plans, and $6.0 million (2006 - $2.9 million) is included in other long-term liabilities.

The following table reconciles the expense recorded for the other unit based compensation plans.
	Year ended December 31,
	2007		2006
Cash general and administrative	$	11,189	$	3,807
Non-cash unit based compensation
(included in general and administrative)		3,871		10,478
	$	15,060	$	14,285

12.	Income taxes

In 2007, future income tax expense includes $88.4 million relating to the enactment of Bill C-52, Budget Implementation Act 2007 by the Canadian government. This bill contains legislation to tax publicly traded trusts including the Trust. As a result of this legislation, the Trust is now required to record the future tax effect of the temporary differences on its flow through entities that are expected to reverse subsequent to 2010.

Although the Trust believes it will be subject to additional tax under the new legislation, the estimated effective tax rate on temporary difference reversals after 2011 may change in future periods. As the legislation is new, future technical interpretations of the legislation could occur and could materially affect management’s estimate of the future income tax liability.

The amount and timing of reversals of temporary differences will also depend on the Trust’s future operating results, acquisitions and dispositions of assets and liabilities, and distribution policy. A significant change in any of the preceding assumptions could materially affect the Trust’s estimate of the future tax liability.

Provident follows the liability method for calculating future income taxes. Under this method, future income tax assets and liabilities are recognized based on the estimated tax effects of temporary differences in the carrying value of assets and liabilities and their respective tax bases, using income tax rates substantively enacted on the consolidated balance sheet date:

	Year ended December 31,
Future income taxes	2007		2006
Petroleum and natural gas properties, production facilities and other	$	332,301	$	266,156
Midstream facilities		117,699		42,850
	$	450,000	$	309,006

The income tax provision differs from the expected amount calculated by applying the Canadian combined federal and provincial income tax rate of 32.81 percent (2006 – 34.67 percent) as follows:

	Year ended December 31,
	2007			2006
Expected income tax expense	$	23,310		$	40,736
Increase (decrease) resulting from:
Future income tax expense relating to enactment of Bill C-52,
Budget Implementation Act 2007		88,352			-
Non-deductible Crown charges and other payments		-			8,135
Federal resource allowance		-			(5,742	)
Alberta Royalty Tax Credit		-			(173	)
Income of the Trust and other		(73,045	)		(70,999	)
Capital Taxes		3,762			1,314
Witholding tax and other		3,425			3,308
Income tax rate changes		(5,193	)		(3,752	)
Income tax expense (recovery)	$	40,611		$	(27,173	)

13.

Financial instruments

Financial instruments of the Trust carried on the consolidated balance sheet consist mainly of cash and cash equivalents, accounts receivable, current liabilities, commodity, foreign currency and interest rate contracts and long-term debt. Except as disclosed in note 7, as at December 31, 2007 and 2006, there were no significant differences between the carrying value of these financial instruments and their estimated fair value.

Substantially all of the Trust's accounts receivable are due from customers and joint venture partners in the oil and gas and midstream services and marketing industries and are subject to credit risk. The Trust partially mitigates associated credit risk by limiting transactions with certain counterparties to limits imposed by the Trust based on the Trust’s assessment of the creditworthiness of such counterparties. The carrying value of accounts receivable reflects management's assessment of the associated credit risks. With respect to counterparties to financial instruments, the Trust partially mitigates associated credit risk by limiting transactions to counterparties with investment grade credit ratings and obtaining financial guarantees from certain counterparties.

Provident’s commodity price risk management program is intended to minimize the volatility of commodity prices and to assist with stabilizing cash flow and distributions. Provident seeks to accomplish this through the use of financial instruments from time to time to reduce its exposure to fluctuations in commodity prices and foreign exchange rates.

With respect to financial instruments, Provident could be exposed to losses if a counterparty fails to perform in accordance with the terms of the contract. This risk is managed by diversifying the derivative portfolio among counterparties meeting certain financial criteria.

i)	Commodity price

Crude oil

In 2007, Provident paid $17.6 million (2006 - $5.7 million) to settle various oil market based contracts on an aggregate volume of 3.4 million barrels (2006 – 2.1 million barrels). The estimated value of contracts in place if settled at market prices at December 31, 2007 would have resulted in an opportunity cost of $98.2 million (2006 – $7.2 million gain).

b)	Natural Gas

In 2007, Provident received $9.6 million (2006 - $7.6 million) to settle various natural gas market based contracts on an aggregate of 16.7 million gigajoules (“gj”) (2006 – 9.5 million gj’s). The estimated value of contracts in place if settled at market prices at December 31, 2007 would have resulted in an opportunity cost of $18.0 million (2006 – $8.6 million gain).

Midstream

In 2007, Provident received $17.9 million (2006 – paid $0.6 million) to settle Midstream oil market based contracts on an aggregate volume of 1.2 million barrels (2006 - 1.5 million barrels) and paid $48.7 million (2006 -$27.1 million) to settle Midstream natural gas market based contracts on an aggregate volume of 25.3 million gj’s (2006 – 15.3 million gj’s). In addition, Provident paid $48.2 million (2006 – received $12.3 million) to settle Midstream NGL market based contracts on an aggregate volume of 7.2 million barrels (2006 – 2.5 million barrels). The estimated value of contracts in place if settled at market prices at December 31, 2007 would have resulted in an opportunity cost of $261.6 million (2006 – $68.8 million).

ii)	Foreign exchange contracts

In 2007, Provident received $6.3 million to settle various foreign exchange based contracts (2006 - $0.4 million). The estimated value of contracts in place if settled at foreign exchange rates at December 31, 2007 would have resulted in an opportunity cost of $0.1 million (2006 – $0.1 million gain).

iii)	Interest rate contracts

As at December 31, 2007 the estimated value of contracts in place settled at December 31 interest rates was an opportunity cost of $0.1 million (December 31, 2006 – nil).

The contracts in place at December 31, 2007 are summarized in the following tables:
COGP
		Volume
Year Product		(Buy)Sell		Terms	Effective Period
2008	Crude Oil	250	Bpd	Puts US $63.75 per bbl	January 1 - December 31
		150	Bpd	Puts US $75.00 per bbl	January 1 - December 31
		1,000	Bpd	Puts US $67.50 per bbl	January 1 - December 31
		250	Bpd	Participating Swap US $60.00 per bbl (max to 75.3% above the floor price)	January 1 - December 31
		375	Bpd	Participating Swap US $65.00 per bbl (52.7% above the floor price)	January 1 - December 31
		450	Bpd	Participating Swap US $62.50 per bbl (max to 52.5% above the floor price)	January 1 - June 30
		450	Bpd	Participating Swap US $62.50 per bbl (67.8% above the floor price)	January 1 - June 30
		850	Bpd	Participating Swap US $65.00 per bbl (57.5% above the floor price)	January 1 - June 30
		850	Bpd	Participating Swap US $62.50 per bbl (max to 69.9% above the floor price)	January 1 - June 30
		300	Bpd	Participating Swap US $62.50 per bbl (max to 51% above the floor price)	July 1 - December 31
		625	Bpd	Participating Swap US $65.00 per bbl (54.25% above the floor price)	July 1 - December 31
		925	Bpd	Participating Swap US $62.50 per bbl (66% above the floor price)	July 1 - December 31
		325	Bpd	Participating Swap US $67.20 per bbl (70% above the floor price)	July 1 - December 31
	Natural Gas	1,000	Gjpd	Puts Cdn $6.00 per gj	January - March 31
		5,000	Gjpd	Participating Swap Cdn $6.48 per gj (max to 100% above the floor price)	January - March 31
		4,000	Gjpd	Participating Swap Cdn $7.00 per gj (52.8% above the floor price)	January - March 31
		2,000	Gjpd	Participating Swap Cdn $7.00 per gj (max to 70% above the floor price)	January - March 31
		4,000	Gjpd	Participating Swap Cdn $7.25 per gj (56% above the floor price)	January - March 31
		8,000	Gjpd	Participating Swap Cdn $7.50 per gj (70% above the floor price)	January - March 31
		8,000	Gjpd	Participating Swap Cdn $7.75 per gj (70% above the floor price)	January - March 31
		2,000	Gjpd	Participating Swap Cdn $8.00 per gj (max to 75.5% above the floor price)	January - March 31
		300	Gjpd	Participating Swap Cdn $7.60 per gj (53.5% above the floor price)	January 1 - June 30
		2,000	Gjpd	Participating Swap Cdn $6.00 per gj (max up to 85% above the floor price)	January 1 - October 31
		2,000	Gjpd	Participating Swap Cdn $7.50 per gj (max to 25% above the floor price)	January 1 - October 31
		900	Gjpd	Participating Swap Cdn $7.60 per gj (41% above the floor price)	January 1 - October 31
		2,000	Gjpd	Participating Swap Cdn $6.00 per gj (56% above the floor price)	April 1 - October 31
		2,000	Gjpd	Participating Swap Cdn $7.00 per gj (48.6% above the floor price)	April 1 - October 31
		1,000	Gjpd	Participating Swap Cdn $6.75 per gj (51% above the floor price)	April 1 - December 31
		1,000	Gjpd	Participating Swap Cdn $7.00 per gj (max up to 85% above the floor price)	April 1 - December 31
		1,000	Gjpd	Participating Swap Cdn $7.50 per gj (max to 23.5% above the floor price)	April 1 - December 31
		1,000	Gjpd	Participating Swap Cdn $6.50 per gj (50% above the floor price)	November 1 - December 31
		1,000	Gjpd	Participating Swap Cdn $6.50 per gj (max up to 90% above the floor price)	November 1 - December 31
		2,000	Gjpd	Participating Swap Cdn $6.75 per gj (max up to 90% above the floor price)	November 1 - December 31
		2,000	Gjpd	Participating Swap Cdn $7.00 per gj (max up to 85% above the floor price)	November 1 - December 31
		2,000	Gjpd	Participating Swap Cdn $7.50 per gj (max up to 100% above the floor price)	November 1 - December 31
		400	Gjpd	Participating Swap Cdn $7.75 per gj (23% above the floor price)	November 1 - December 31
2009	Crude Oil	125	Bpd	Participating Swap US $60.00 per bbl (60% above the floor price)	January 1 - December 31
		825	Bpd	Participating Swap US $62.50 per bbl (59.5% above the floor price)	January 1 - December 31
		400	Bpd	Participating Swap US $62.50 per bbl (max to 50% above the floor price)	January 1 - June 30
		1,500	Bpd	Participating Swap US $62.50 per bbl (62.6% above the floor price)	January 1 - June 30
		775	Bpd	Participating Swap US $62.50 per bbl (60.4% above the floor price)	July 1 - December 31
	Natural Gas	400	Gjpd	Participating Swap Cdn $7.75 per gj (23% above the floor price)	January 1 - December 31
		1,000	Gjpd	Participating Swap Cdn $6.50 per gj (50% above the floor price)	January 1 - March 31
		1,000	Gjpd	Participating Swap Cdn $6.50 per gj (max up to 90% above the floor price)	January 1 - March 31
		1,000	Gjpd	Participating Swap Cdn $6.75 per gj (51% above the floor price)	January 1 - March 31
		2,000	Gjpd	Participating Swap Cdn $6.75 per gj (max up to 90% above the floor price)	January 1 - March 31
		1,000	Gjpd	Participating Swap Cdn $7.00 per gj (max up to 85% above the floor price)	January 1 - March 31
		2,000	Gjpd	Participating Swap Cdn $7.00 per gj (max up to 85% above the floor price)	January 1 - March 31
		3,000	Gjpd	Participating Swap Cdn $7.50 per gj (max to 62% above the floor price)	January 1 - March 31

USOGP
		Volume
Year Product		(Buy)Sell		Terms	Effective Period
2008	Crude Oil	125-325 Bpd		US $59.25 per bbl	January 1 - December 31
		325	Bpd	US $70.37 per bbl	January 1 - December 31
		790	Bpd	US $72.89 per bbl	January 1 - December 31
		425	Bpd	Participating Swap US $60.00 per bbl (max to 76% above the floor price)	January 1 - December 31
		2,650	Bpd	US $68.44 per bbl	January 1 - June 30
		250	Bpd	Costless Collar US $66.00 floor, US $69.25 ceiling	January 1 - June 30
		250	Bpd	Costless Collar US $66.00 floor, US $71.50 ceiling	January 1 - June 30
		250	Bpd	US $71.24 per bbl	July 1 - September 30
		2,500	Bpd	Participating Swap US $60.00 per bbl (max to 53.3% above the floor price)	July 1 - September 30
		250	Bpd	US $70.66 per bbl	July 1 - December 31
		250	Bpd	Participating Swap US $70.00 per bbl (61.8% above the floor price)	July 1 - December 31
		2,000	Bpd	Participating Swap US $60.00 per bbl (max to 59% above the floor price)	October 1 - December 31
		750	Bpd	US $70.49 per bbl	October 1 - December 31
		150	Bpd	Participating Swap US $60.00 per bbl (78% above the floor price)	January 1 - December 31
		250	Bpd	Participating Swap US $62.50 per bbl (57.5% above the floor price)	January 1 - December 31
		250	Bpd	Participating Swap US $65.00 per bbl (52% above the floor price)	January 1 - December 31
	Natural Gas	48,643	Mmbtu	US $8.01 per mmbtu (10)	January 1 - December 31
2009	Crude Oil	125 - 325 Bpd		US $59.25 per bbl	January 1 - December 31
		460	Bpd	US $69.95 per bbl	January 1 - December 31
		679	Bpd	US $71.38 per bbl	January 1 - December 31
		410	Bpd	Participating Swap US $60.00 per bbl (max to 67.99% above the floor price)	January 1 - December 31
		250	Bpd	Participating Swap US $62.50 per bbl (max to 67.25% above the floor price)	January 1 - December 31
		210	Bpd	Costless Collar US $60.00 floor, US $79.50 ceiling	January 1 - December 31
		250	Bpd	Participating Swap US $70.00 per bbl (61.8% above the floor price)	January 1 - December 31
		500	Bpd	Participating Swap US $60.00 per bbl (max to 55.5% above the floor price)	January 1 - September 30
		2,000	Bpd	Participating Swap US $60.00 per bbl (max to 59% above the floor price)	January 1 - September 30
		500	Bpd	US $70.92 per bbl	January 1 - March 31
		500	Bpd	US $72.25 per bbl	April 1 - June 30
		250	Bpd	US $72.47 per bbl	October 1 - December 31
		250	Bpd	Participating Swap US $60.00 per bbl (70% above the floor price)	October 1 - December 31
		500	Bpd	Participating Swap US $65.00 per bbl (54% above the floor price)	October 1 - December 31
		500	Bpd	Participating Swap US $65.00 per bbl (50% above the floor price)	October 1 - December 31
		250	Bpd	US $70.00 per bbl	December 1 - December 31
		425	Bpd	Participating Swap US $60.00 per bbl (61.45% above the floor price)	January 1 - December 31
	Natural Gas	44,071	Mmbtu	US $8.01 per mmbtu (10)	January 1 - December 31
2010	Crude Oil	609	Bpd	US $70.42 per bbl	January 1 - December 31
		500	Bpd	US $69.75 per bbl	January 1 - December 31
		933	Bpd	Participating Swap US $60.00 per bbl (max to 59.01% above the floor price)	January 1 - December 31
		250	Bpd	Participating Swap US $62.50 per bbl (56.20% above the floor price)	January 1 - December 31
		183	Bpd	Costless Collar US $60.00 floor, US $79.25 ceiling	January 1 - December 31
		183	Bpd	US $69.59 per bbl	January 1 - December 31
		250	Bpd	Participating Swap US $70.00 per bbl (61.8% above the floor price)	January 1 - March 31
		250	Bpd	Participating Swap US $60.00 per bbl (70% above the floor price)	January 1 - June 30
		500	Bpd	Participating Swap US $65.00 per bbl (50% above the floor price)	January 1 - June 30
		250	Bpd	US $72.47 per bbl	January 1 - June 30
		542	Bpd	US $72.05 per bbl	January 1 - July 31
		500	Bpd	Participating Swap US $70.00 per bbl (37.3% above the floor price)	April 1 - September 30
	Natural Gas	40,471	Mmbtu	US $8.01 per mmbtu (10)	January 1 - December 31
2011	Crude Oil	1,377	Bpd	Participating Swap US $60.00 per bbl (max to 53.11% above the floor price)	January 1 - December 31
		177	Bpd	Costless Collar US $60.00 floor, US $77.60 ceiling	January 1 - December 31
		177	Bpd	US $69.15 per bbl	January 1 - December 31
	Natural Gas	40,400	Mmbtu	US $8.01 per mmbtu (10)	January 1 - March 31

Midstream
		Volume
Year	Product	(Buy)Sell		Terms	Effective Period
2008	Crude Oil	2,250	Bpd	Costless Collar US $68.50 floor, US $73.72 ceiling	January 1 - December 31
		500	Bpd	Costless Collar US $64.00 floor, US $74.50 ceiling	January 1 - September 30
		500	Bpd	Costless Collar US $73.00 floor, US $80.00 ceiling	January 1 - June 30
		250	Bpd	US $65.60 per bbl	January 1 - December 31
		250	Bpd	US $66.65 per bbl	January 1 - December 31
		9,635	Bpd	Cdn $76.02 per bbl	January 1 - December 31
		(845	Bpd	US $74.64 per bbl (4)	January 1 - March 31
		(10,535	Bpd	US $86.93 per bbl (4)	January 1 - March 31
	Natural Gas	(75,767	Gjpd	Cdn $8.31 per gj	January 1 - December 31
	Foreign Exchange			Sell US $6,202,175 per month @1.1198 (5)	January 1 - December 31
				Sell US $1,107,166 per month @1.1035 (5)	January 1 - June 30
				Sell US $974,222 per month @1.1255 (5)	January 1 - September 30
	Propane	3,225	Bpd	US $1.5308 per gallon (6) (9)	January 1 - January 31
		1,206	Bpd	US $1.5382 per gallon (6) (9)	February 1 - February 29
		5,645	Bpd	US $1.2829 per gallon (6) (9)	January 1 - February 29
		850	Bpd	US $1.2487 per gallon (4) (6)	January 1 - March 31
		10,287	Bpd	US $1.4595 per gallon (4) (6)	January 1 - March 31
	Normal Butane	2,258	Bpd	US $1.8148 per gallon (7) (9)	January 1 - January 31
		2,230	Bpd	US $1.647 per gallon (4) (7)	January 1 - March 31
		150	Bpd	US $1.4325 per gallon (4) (7)	January 1 - March 31
	ISO Butane	150	Bpd	US $1.4453 per gallon (4) (8)	January 1 - March 31
		1,720	Bpd	US $1.6424 per gallon (4) (8)	January 1 - March 31
	Power	(20	MW/hpd	Cdn $76.43 per MW/h (12)	January 1 - December 31
2009	Crude Oil	2,500	Bpd	Costless Collar US $64.80 floor, US $69.36 ceiling	January 1 - December 31
		7,158	Bpd	Cdn $74.23 per bbl	January 1 - December 31
		250	Bpd	US $64.60 per bbl	January 1 - December 31
		250	Bpd	US $66.65 per bbl	January 1 - December 31
		500	Bpd	Costless Collar US $70.00 floor, US $79.00 ceiling	January 1 - June 30
		1,000	Bpd	Participating Swap US $63.13 per bbl (56% above the floor price)	July 1 - August 31
		598	Bpd	Participating Swap US $75.64 per bbl (55.7% above the floor price)	July 1 - November 30
		500	Bpd	Participating Swap Cdn $73.38 per bbl (48.9% above the floor price)	September 1 - November 30
	Natural Gas	(60,769	Gjpd	Cdn $8.14 per gj	January 1 - December 31
		(2,792	Gjpd	Participating Swap Cdn $7.73 per gj (39% below the ceiling price)	July 1 - November 30
		(2,810	Gjpd	Cdn $6.62 per gj	September 1 - October 31
		(2,810	Gjpd	Costless Collar Cdn $6.20 floor, Cdn $7.10 ceiling	September 1 - October 31
	Foreign Exchange			Sell US $6,699,029 per month @1.1113 (5)	January 1 - December 31
				Sell US $1,055,833 per month @1.099 (5)	January 1 - June 30
				Sell US $1,972,561 per month @1.0245 (5)	July 1 - August 31
				Sell US $596,166 per month @0.9815 (5)	July 1 - October 31
				Sell US $1,686,650 per month @0.9620 (5)	September 1 - October 31
				Sell US $1,163,100 per month @1.013 (5)	November 1 - November 30
2010	Crude Oil	1,500	Bpd	Costless Collar US $62.90 floor, US $67.48 ceiling	January 1 - December 31
		6,502	Bpd	Cdn $73.16 per bbl	January 1 - December 31
		250	Bpd	US $66.65 per bbl	January 1 - December 31
		500	Bpd	Participating Swap Cdn $61.50 per bbl (50% above the floor price)	July 1 - August 31
		376	Bpd	Participating Swap Cdn $70.91 per bbl (56% above the floor price)	July 1 - October 31
		820	Bpd	Participating Swap US $73.63 per bbl (51.8% above the floor price)	January 1 - November 30
	Natural Gas	(48,527	Gjpd	Cdn $7.89 per gj	January 1 - December 31
		(4,089	Gjpd	Participating Swap Cdn $7.62 per gj (31.3% below the ceiling price)	January 1 - November 30
	Foreign Exchange			Sell US $4,721,469 per month @1.1101 (5)	January 1 - December 31
				Sell US $582,821 per month @1.0159 (5)	January 1 - August 31
				Sell US $1,407,419 per month @0.9781 (5)	July 1 - August 31
				Sell US $587,903 per month @1.0165 (5)	July 1 - November 30
				Sell US $2,254,103 per month @0.9577 (5)	September 1 - October 31
				Sell US $1,750,992 per month @1.0176 (5)	September 1 - November 30

Midstream, cont'd.
Year	Product	(Buy)Sell		Terms	Effective Period
2011	Crude Oil	5,389	Bpd	Cdn $71.68 per bbl	January 1 - December 31
		250	Bpd	Participating Swap US $63.00 per bbl (64% above the floor price)	January 1 - December 31
		500	Bpd	Costless Collar US $65.00 floor, US $75.00 ceiling	January 1 - June 30
		2,000	Bpd	Costless Collar US $58.50 floor, US $72.69 ceiling	July 1 - September 30
	Natural Gas	(37,595) Gjpd		Cdn $7.31 per gj	January 1 - December 31
	Foreign Exchange			Sell US $980,417 per month @1.0805 (5)	January 1 - June 30
				Sell US $3,587,999 per month @1.0931 (5)	July 1 - September 30
				Sell US $479,063 per month @0.9725 (5)	January 1 - December 31
2012	Crude Oil	3,647	Bpd	Cdn $72.95 per bbl	January 1 - December 31
		1,141	Bpd	Participating Swap US $66.67 per bbl (59% above the floor price)	April 1 - December 31
		250	Bpd	Participating Swap Cdn $71.50 per bbl (50% above the floor price)	October 1 - December 31
	Natural Gas	(25,787) Gjpd		Cdn $7.23 per gj	January 1 - December 31
	Foreign Exchange			Sell US $1,437,986 per month @0.9657 (5)	July 1 - December 31
				Sell US $976,436 per month @0.9413 (5)	April 1 - October 31
				Sell US $1,634,227 per month @0.9832 (5)	October 1 - December 31
2013	Crude Oil	250	Bpd	Cdn $75.32 per bbl	January 1 - January 31
		750	Bpd	Participating Swap US $70.92 per bbl (50.6% above the floor price)	January 1 - January 31
		250	Bpd	Participating Swap Cdn $71.50 per bbl (50% above the floor price)	January 1 - January 31
	Natural Gas	(7,025) Gjpd		Cdn $7.19 per gj	January 1 - January 31
	Foreign Exchange			Sell US $1,651,990 per month @0.9832 (5)	January 1 - January 31
Corporate
Year	Product	(Buy)Sell		Terms	Effective Period
2008	Foreign Exchange			Sell US $9,000,000 @.9701 (5.1)	January 25
				Sell US $3,000,000 @1.0105 (5.1)	February 25
	Interest Rate			Pay Fixed rate of 4.8852% - Receive 3M CAD BA on Cdn $50MM Notional (11)	January 1 - July 31

(1) The above table represents a number of transactions entered into over an extended period of time.
(2) Natural Gas contracts are settled against AECO monthly index.

(3) Crude Oil contracts are settled against NYMEX WTI calendar average

(4) Conversion of Crude Oil BTU positions to liquids.

(5) US dollar contracts settled against Bank of Canada noon rate average.

(5.1) US dollar cashflows sold forward.

(6) Propane contracts are settled against Belvieu C3 TET.

(7) Normal Butane contracts are settled against Belvieu NC4 NON-TET.

(8) ISO Butane contracts are settled against Belvieu IC4 NON-TET.

(9) Midstream inventory price stabilization contracts.

(10) Natural Gas contracts are settled against Natural Gas-Michcon Citygate Inside FERC.

(11) Settles quarterly against 3M CAD BA interest rate.

(12) Power contracts are settled monthly against the average hourly price of electricity as published by the AESO in $/MWh.

14. Cash reserve for future site reclamation

Provident established a cash reserve effective May 1, 2001 for future site reclamation expenditures relating to its Canadian oil and gas production. In accordance with the royalty agreement, Provident funds the reserve by paying $0.30 per barrel of oil equivalent produced on a 6:1 basis into a segregated cash account. Actual expenditures incurred are then funded from the cash in this account. The cash reserve was depleted in 2006 as actual expenditures exceeded contributions to the reserve.

15. Commitments

Provident has office lease commitments that extend through June 2022. Future minimum lease payments for the following five years are: 2008 - $8.6 million; 2009 - $10.6 million; 2010 - $10.5 million; 2011 - $10.4 million; and 2012 -$10.2 million.

In relation to the midstream services and marketing segment, Provident is committed to minimum lease payments under the terms of various rail tank car leases for the following five years: 2008 – $6.6 million; 2009 – $5.4 million; 2010 – $3.9 million; 2011 – $2.7 million, and 2012 – $1.3 million. Additionally, under an arrangement to use a third party interest in the Younger plant, Provident has a commitment to make payments calculated with reference to a number of variables including return on capital. Payments for the next five years are estimated as follows: 2008 - $4.3 million; 2009 - $4.0 million; 2010 - $3.8 million; 2011 – $4.1 million and 2012 - $4.3 million.

In relation to the United States oil and natural gas production segment, Provident’s U.S. subsidiaries have performance obligations that are secured, in whole or in part, by surety bonds. These obligations primarily cover self-insurance and other programs where governmental organizations require such support. These surety bonds are issued by financial institutions and are required to be reimbursed by Provident’s U.S. subsidiaries if drawn upon. At December 31, 2007, Provident’s U.S. subsidiaries had obtained various surety bonds for U.S. $14.3 million (2006 – U.S. $4.9 million).

In relation to the United States oil and natural gas production segment, Provident leases certain property and equipment under operating leases. Future minimum lease payments for the following five years are as follows: 2008 – U.S. $0.9 million; 2009 – U.S. $0.8 million; 2010 – U.S. $0.7 million; 2011 – U.S. $0.7 million and 2012 – U.S. $0.7 million.

16. Subsequent event

In February 2008, the Trust announced that it has retained Morgan Stanley as financial advisor in connection with a strategic review process with the objective of selling the operations that comprise the United States oil and natural gas production (USOGP) segment. USOGP includes the Trust’s interest in the MLP, the related general partner interest, as well as the Trust’s interest in BreitBurn Energy Company L.P.

As at December 31, 2007 the Trust owned approximately 22 percent of the MLP and approximately 96 percent of BreitBurn Energy Company L.P. Pursuant to the announcement, the Trust will account for USOGP as discontinued operations beginning in the first quarter of 2008.

17. Segmented information

The Trust’s business activities are conducted through three business segments: Canadian oil and natural gas production (COGP), United States oil and natural gas production (USOGP) and Midstream.

Oil and natural gas production in Canada and the United States includes exploitation, development and production of crude oil and natural gas reserves. Midstream includes processing, extraction, transportation, loading and storage of natural gas liquids, and marketing of natural gas liquids.

Geographically the Trust operates in Canada and the USA in the oil and gas production business segment. The geographic components have been presented for the oil and natural gas business as well as the Midstream business that operates in both Canada and the USA.

				Year ended December 31, 2007
	Canadian Oil			U.S. Oil and			Total Oil and
	and Natural Gas			Natural Gas			Natural Gas
	Production			Production				Production		Midstream (1)				Total
Revenue
Gross production revenue	$	454,179		$	278,414		$	732,593			$	-		$	732,593
Royalties		(87,046	)		(31,654	)		(118,700	)			-			(118,700	)
Product sales and service revenue		-			-			-				1,958,372			1,958,372
Realized gain (loss) on financial derivative
instruments		1,728			(7,959	)		(6,231	)			(74,474	)		(80,705	)
		368,861			238,801			607,662				1,883,898			2,491,560
Expenses
Cost of goods sold		-			11,143			11,143				1,594,639			1,605,782
Production, operating and maintenance		112,387			81,699			194,086				14,094			208,180
Transportation		8,193			3,102			11,295				16,825			28,120
Foreign exchange (gain) loss and other		(573	)		-			(573	)			3,996			3,423
General and administrative		27,102			45,188			72,290				28,669			100,959
		147,109			141,132			288,241				1,658,223			1,946,464
Earnings before interest, taxes, depletion,
depreciation, accretion and other non-cash items		221,752			97,669			319,421				225,675			545,096
Other revenue
Unrealized loss on financial derivative		(21,324	)		(110,040	)		(131,364	)			(192,920	)		(324,284	)
Other expenses
Depletion, depreciation and accretion		256,723			50,253			306,976				44,388			351,364
Interest on bank debt		11,055			7,439			18,494				33,166			51,660
Interest and accretion on convertible debentures		3,672			10,660			14,332				11,015			25,347
Amortization of deferred financing charges		-			-			-				-			-
Unrealized foreign exchange loss and other		779			2,593			3,372				-			3,372
Dilution gain		-			(260,324	)		(260,324	)			-			(260,324	)
Non-cash unit based compensation		3,698			5,950			9,648				4,366			14,014
Internal management charge		(1,482	)		1,482			-				-			-
Capital tax expense		3,762			-			3,762				-			3,762
Current and withholding tax (recovery) expense		(254	)		10			(244	)			6,606			6,362
Future income tax expense (recovery) (2)		(122,590	)		58,843			(63,747	)			94,234			30,487
		155,363			(123,094	)		32,269				193,775			226,044
Non-controlling interest - USOGP		-			(35,666	)		(35,666	)			-			(35,666	)
Non-controlling interest - exchangeables		-			-			-				-			-
Net income (loss) for the period	$	45,065		$	146,389		$	191,454			$	(161,020	)	$	30,434

(1)	Included in the Midstream segment is product sales and service revenue of $297.8 million associated with U.S. operations.

(2)	Future income tax expense (recovery) includes a charge of $88.4 million relating to the enactment of Bill C-52, Budget Implementation Act 2007 by the Canadian government (see note 12).

100

			As at and for the year ended December 31, 2007
	Canadian Oil		U.S. Oil and		Total Oil and
	and Natural		Natural Gas		Natural Gas
	Gas Production		Production		Production		Midstream		Total
Selected balance sheet items
Capital assets
Property, plant and equipment net	$	1,773,209	$	2,008,549	$	3,781,758	$	737,062	$	4,518,820
Intangible assets		-		3,763		3,763		171,793		175,556
Goodwill		416,890		-		416,890		100,409		517,299
Capital expenditures
Capital Expenditures		146,209		69,009		215,218		31,904		247,122
Corporate acquisitions		469,795		-		469,795		-		469,795
Oil and gas property acquisitions, net		13,050		1,015,803		1,028,853		-		1,028,853
Goodwill additions		85,946		-		85,946		-		85,946
Working capital
Accounts receivable		75,292		79,457		154,749		262,813		417,562
Petroleum product inventor y		-		5,636		5,636		84,638		90,274
Accounts payable and accrued liabilities		132,452		77,442		209,894		214,574		424,468
Long-term debt - revolving term credit
facilities		230,999		368,836		599,835		692,997		1,292,832
Long-term debt - convertible debentures		35,129		115,925		151,054		105,386		256,440
Financial derivative instruments	$	13,559	$	102,859	$	116,418	$	261,587	$	378,005

101

				Year ended December 31, 2006
	Canadian Oil			U.S. Oil and			Total Oil and
	and Natural			Natural Gas			Natural Gas
	Gas Production			Production			Production			Midstream (1)			Total
Revenue
Gross production revenue	$	402,095		$	176,160		$	578,255		$	-		$	578,255
Royalties		(81,225	)		(17,315	)		(98,540	)		-			(98,540	)
Product sales and service revenue		-			-			-			1,764,392			1,764,392
Realized gain (loss) on financial derivative
instruments		4,371			(2,505	)		1,866			(15,406	)		(13,540	)
		325,241			156,340			481,581			1,748,986			2,230,567
Expenses
Cost of goods sold		-			-			-			1,471,171			1,471,171
Production, operating and maintenance		97,626			52,008			149,634			22,619			172,253
Transportation		5,114			-			5,114			14,672			19,786
Foreign exchange gain and other		(9	)		-			(9	)		(2,728	)		(2,737	)
Cash general and administrative		24,065			26,519			50,584			23,621			74,205
		126,796			78,527			205,323			1,529,355			1,734,678
Earnings before interest, taxes, depletion,
depreciation, accretion and other non-cash items		198,445			77,813			276,258			219,631			495,889
Other revenue
Unrealized gain (loss) on financial derivative
instruments		17,299			7,735			25,034			(68,348	)		(43,314	)
Other expenses
Depletion, depreciation and accretion		168,953			31,058			200,011			49,128			249,139
Interest on bank debt		10,082			4,861			14,943			19,723			34,666
Interest and accretion on convertible debentures		5,746			5,828			11,574			12,345			23,919
Amortization of deferred financing charges		956			786			1,742			2,112			3,854
Unrealized foreign exchange loss and other		-			-			-			418			418
Dilution gain		-			-			-			-			-
Non-cash unit based compensation		4,320			12,476			16,796			6,287			23,083
Internal management charge		(1,280	)		1,280			-			-			-
Capital tax expense		1,314			-			1,314			-			1,314
Current and withholding tax expense		(2,124	)		3,332			1,208			4,621			5,829
Future income tax expense (recovery)		(56,161	)		20,297			(35,864	)		1,548			(34,316	)
		131,806			79,918			211,724			96,182			307,906
Non-controlling interest - USOGP		-			2,995			2,995			-			2,995
Non-controlling interest - exchangeables		485			37			522			232			754
Net income for the period	$	83,453		$	2,598		$	86,051		$	54,869		$	140,920
(1) Included in the Midstream segment is product sales and service revenue of $332.9 million associated with U.S. operations.

102

				As at and for the year ended December 31, 2006
	Canadian Oil			U.S. Oil and			Total Oil and
	and Natural			Natural Gas			Natural Gas
	Gas Production			Production			Production			Midstream		Total
Selected balance sheet items
Capital assets
Property, plant and equipment net	$	1,211,112		$	380,451		$	1,591,563		$	741,974	$	2,333,537
Intangible assets		-			-			-			193,592		193,592
Goodwill		330,944			-			330,944			100,409		431,353
Capital expenditures
Capital expenditures		70,088			54,337			124,425			66,008		190,433
Corporate acquisitions		-			-			-			1,036		1,036
Oil and gas property acquisitions, net		483,633			(2,008	)		481,625			-		481,625
Goodwill additions		-			-			-			2,285		2,285
Working capital
Accounts receivable		58,250			24,744			82,994			187,141		270,135
Petroleum product inventor y		-			-			-			85,868		85,868
Accounts payable and accrued liabilities		86,305			52,626			138,931			156,072		295,003
Long-term debt - revolving term credit
facilities		172,980			11,072			184,052			518,941		702,993
Long-term debt - convertible debentures		44,553			117,470			162,023			123,769		285,792
Financial derivative instruments
(asset) liability	$	(7,520	)	$	(8,417	)	$	(15,937	)	$	68,795		52,858

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18. Related party transactions

Included in accounts receivable as at December 31, 2007 is $32.8 million with related parties. Of this amount, $22.5 million represents a net receivable from Quicksilver, reflecting cash collections made on behalf of a subsidiary of the Trust in connection with the acquisition of assets from Quicksilver in the fourth quarter of 2007, net of advances. Quicksilver owns approximately 32 percent of the outstanding units of the MLP, a subsidiary of the Trust. The remaining $10.3 million relates to sales of crude oil by a subsidiary of the trust to a buyer whose Chairman of the Board and Chief Executive Officer is also a director of the general partner of the subsidiary of the Trust.

19. Reconciliation of financial statements to United States generally accepted accounting principles (U.S. GAAP)

The consolidated financial statements have been prepared in accordance with accounting principles generally accepted in Canada (“Canadian GAAP”). Any differences in accounting principles to U.S. GAAP as they pertain to the accompanying financial statements are not material except as described below. All adjustments are measurement differences. Disclosure items are not noted.

Consolidated Statements of Earnings - U.S. GAAP
For the year ended December 31, (Cdn $000s)	2007			2006
Net income as reported	$	30,434		$	140,920
Adjustments
Depletion, depreciation and accretion (a)		72,485			12,146
Depletion, depreciation and accretion other (a)		(181,551	)		(382,230	)
General and administrative (d)		483			(483	)
Future income tax recovery (a) (b)		23,625			110,898
Accretion on convertible debentures (e)		2,802			2,694
Non-controlling interest		(2,895	)		754
Net loss – U.S. GAAP	$	(54,617	)	$	(115,301	)
Other comprehensive (loss) income		(26,000	)		(509	)
Comprehensive income (loss)		(80,617	)		(115,810	)
Net loss per unit - basic and diluted	$	(0.24	)	$	(0.59	)

Condensed Consolidated Balance Sheet
As at December 31, (Cdn$ 000s)	2007						2006
	Canadian						Canadian
	GAAP			U.S. GAAP			GAAP			U.S. GAAP
Assets
Deferred financing charges (e)	$	-		$	14,809		$	12,351		$	12,351
Property, plant and equipment (a)		4,518,820			3,983,181			2,333,537			1,906,964
Liabilities and unitholders’ equity
Current portion of convertible debentures (e)		19,198			19,931			-			-
Long-term debt - revolving term credit facilities (e)		1,292,832			1,300,645			702,993			702,993
Long-term debt - convertible debentures (e)		256,440			274,113			285,792			300,110
Other long-term liabilities (d)		20,759			20,759			16,305			16,788
Future income taxes (a) (b)		450,000			296,597			309,006			180,122
Non-controlling interests		1,100,136			1,103,031			81,111			81,111
Units subject to redemption (f)		-			2,308,273			-			2,317,196
Convertible debentures equity component (e)		18,213			-			18,522			-
Unitholders’ contributions (f)		2,750,374			-			2,254,048			-
Accumulated other comprehensive (loss) income		(69,188	)		(69,188	)		(42,294	)		(43,187	)
Accumulated income (loss)		268,642			(927,762	)		238,208			(1,044,840	)
Accumulated cash distributions (f)		(1,260,177	)		-			(926,825	)		-

(a)	Under the Canadian cost recovery ceiling test the recoverability of a cost centre is tested by comparing the carrying value of the cost centre to the sum of the undiscounted proved reserve cash flows expected from the cost centre

104

using future price estimates. If the carrying value is not recoverable, the cost centre is written down to its fair value determined by comparing the future cash flows from the proved plus probable reserves discounted at the Trust’s risk free interest rate. Any excess carrying value of the assets on the balance sheet above fair value would be recorded in depletion, depreciation and accretion expense as a permanent impairment. Under U.S. GAAP, companies utilizing the full cost method of accounting for oil and natural gas activities perform a ceiling test on each cost centre using discounted future net revenue from proved oil and natural gas reserves discounted at 10 percent. Prices used in the U.S. GAAP ceiling tests are those in effect at year-end. The amounts recorded for depletion and depreciation have been adjusted in the periods as a result of differences in write down amounts recorded pursuant to U.S. GAAP compared to Canadian GAAP.

In computing its consolidated net earnings for U.S. GAAP purposes, the Trust recorded additional depletion in 2007 of $181.6 million (2006 – $382.2 million) and a related future income tax recovery of $52.2 million (2006 - $114.7 million) as a result of the application of the ceiling test. These charges were not required under the Canadian GAAP ceiling tests.

(b)

The Canadian liability method of accounting for income taxes in CICA handbook Section 3465 “Income taxes” is similar to the United States FAS 109, “Accounting for Income Taxes”, which requires the recognition of deferred tax assets and liabilities for the expected future tax consequences of events that have been recognized in Provident’s financial statements or tax returns. Pursuant to U.S. GAAP, enacted tax rates are used to calculate future taxes, whereas Canadian GAAP uses substantively enacted rates.

In July 2006, the FASB issued FIN 48, “Accounting for Uncertainty in Income Taxes”. The interpretation creates a single model to address uncertainty in tax positions and clarifies the accounting for income taxes by prescribing the minimum recognition threshold a tax position is required to meet before being recognized in the financial statements. The statement also provides guidance on de-recognition, measurement, classification, interest and penalties, accounting in interim periods, disclosures and transitions as well as specifically scopes out accounting for contingencies. FIN 48 is effective for fiscal years beginning after December 15, 2006. The adoption of this statement has not resulted in a Canadian to U.S. GAAP difference.

(c)	The consolidated statements of cash flows and operations and accumulated income are prepared in accordance with Canadian GAAP and conform in all material respects with U.S. GAAP except for the following;

(i)	Canadian GAAP allows for the presentation of funds flow from operations in the consolidated statement of cash flows. This total cannot be presented under U.S. GAAP.

(ii)	U.S. GAAP requires disclosure on the consolidated statement of operations when depreciation, depletion and amortization are excluded from cost of goods sold. This disclosure has not been noted on the face of the consolidated statement of operations.

(d)

Under Canadian GAAP, Provident follows CICA handbook Section 3870 “Stock-based compensation and other stock-based payments” which provides for the presentation and measurement of cash-settled unit-based compensation as liabilities based on the intrinsic value each period. Under U.S. GAAP FAS 123R “Share-based payments”, public entities are required to measure liability awards based on the award’s fair value re-measured at each reporting date until the date of settlement. Compensation cost for each period is based on the change in the fair value of the units for each reporting period and is recognized over the vesting period.

(e)

Under Canadian GAAP Provident applies EIC Abstract 164 “Convertible and other instruments with embedded derivatives” to account for the convertible debentures. Under U.S. GAAP, the convertible debentures are disclosed as long-term debt at their face value versus Canadian GAAP that requires discounting of the convertible debentures, accretion expense to represent the unwinding of the discounted convertible debentures and a value assigned within equity to the conversion feature component of the convertible debentures. In addition, U.S. GAAP requires debt issue costs to be reported as deferred charges on the consolidated balance sheet.

(f)

Under U.S. GAAP, a redemption feature of equity instruments exercisable at the option of the holder requires that such equity be excluded from classification as permanent equity and be reported as temporary equity at the equity’s redemption value. Changes in redemption value in the period (2007 - $505.1 million; 2006 - $188.6 million) are recorded to accumulated earnings. Under Canadian GAAP, such equity instruments are considered to be permanent equity and are presented as unitholder’s equity. The Trust’s units have a redemption feature, which qualify them to be considered under this guidance.

Recent U.S. Accounting Pronouncements

105

Non-controlling interests in consolidated financial statements

In December 2007, the FASB issued FAS 160 “Non-controlling interests in Consolidated Financial Statements.” FAS 160 requires the ownership interests in subsidiaries held by parties other than the parent be clearly presented in the consolidated balance sheet within equity, but separate from the parent’s equity and the amount of consolidated net income attributable to the parent and the non-controlling interest be clearly identified and presented on the face of the consolidated statement of operations. Changes in the parent’s ownership interest should be accounted for consistently as equity transactions. If a subsidiary is deconsolidated, any retained non-controlling equity investment in the former subsidiary should be initially recorded at fair value and the gain or loss on the deconsolidation of the subsidiary is measured using the fair value of any non-controlling equity investment rather than the carrying amount of the retained investment. This statement is effective for fiscal years, and interim periods, beginning on or after December 15, 2008. The application of this standard will impact how the Trust’s balance sheet and statement of operations are presented.

Business combinations

In December 2007, the FASB revised FAS 141 “Business Combinations.” FAS 141 establishes how an acquirer recognizes and measures in its financial statements the identifiable assets and liabilities as well as any non-controlling interest in the acquiree, how an acquirer should recognize and measure goodwill acquired in the business combination or a gain from a bargain purchase, and how an acquirer determines what information to disclose to enable users of the financial statements to evaluate the nature and financial effects of the business combination. The statement specifically addresses the treatment of acquisition costs separate from the acquisition as opposed to including them as part of the acquisition purchase price. This statement applies prospectively to business combinations for which the acquisition date is on or after the beginning of the first annual reporting period beginning on or after December 15, 2008. The adoption of this statement will impact any future business combination with an acquisition date after January 1, 2009.

The fair value option for financial assets and financial liabilities

In February 2007, the FASB issued FAS 159 “The Fair Value Option for Financial Assets and Financial Liabilities.” FAS 159 permits entities to chose to measure eligible items at fair value at specified election dates. The entity would record gains and losses on items for which the fair value option has been elected in earnings at each subsequent reporting date. This statement is effective as of the beginning of an entity’s first fiscal year that begins after November 15, 2007. The Trust does not expect the adoption of this statement to have a material impact on its financial statements.

Fair value measurement

In September 2006, the FASB issued FAS 157 “Fair value measurement.” FAS 157 defines fair value, establishes a framework for measuring fair value in generally accepted accounting principles and expands disclosures about fair value measurements. This statement does not require any new fair value measurements. Fair value is defined in this statement as the exchange price, which is the price in an orderly transaction between market participants to sell the asset or transfer the liability in the market in which the reporting entity would transact for the asset or liability, that is, the principal or most advantageous market for the asset or liability. The statement is effective for financial statements issued for fiscal years beginning after November 15, 2007, and interim periods of those fiscal years. The Trust is currently evaluating the effect that this statement might have on the Trust’s financial statements.

106

ADDITIONAL DISCLOSURE

Certifications and Disclosure Regarding Controls and Procedures.

(a)	Certifications. See Exhibits 99.1 and 99.2 to this Annual Report on Form 40-F.

(b)

Disclosure Controls and Procedures. As of the end of the registrant’s fiscal year ended December 31, 2007, an evaluation of the effectiveness of the registrant’s “disclosure controls and procedures” (as such term is defined in Rules 13a-15(e) and 15d-15(e) of the Securities Exchange Act of 1934, as amended (the “Exchange Act”)) was carried out by the management of Provident Energy Ltd., the administrator of the registrant, with the participation of the Chief Executive Officer (“CEO”) and Chief Financial Officer (“CFO”) of Provident Energy Ltd., who also perform such functions for the registrant. Based upon that evaluation, the CEO and CFO have concluded that as of the end of that fiscal year, the registrant’s disclosure controls and procedures are effective to ensure that information required to be disclosed by the registrant in reports that it files or submits under the Exchange Act is (i) recorded, processed, summarized and reported within the time periods specified in Securities and Exchange Commission rules and forms and (ii) accumulated and communicated to the registrant’s management, including its principal executive officer and principal financial officer, to allow timely decisions regarding required disclosure.

It should be noted that while the CEO and CFO believe that the registrant’s disclosure controls and procedures provide a reasonable level of assurance that they are effective, they do not expect that the registrant’s disclosure controls and procedures or internal control over financial reporting will prevent all errors and fraud. A control system, no matter how well conceived or operated, can provide only reasonable, not absolute, assurance that the objectives of the control system are met.

(c)	Management’s Annual Report on Internal Control Over Financial Reporting. The required disclosure is included in the “Management Report” that accompanies the registrant’s Consolidated Financial Statements for the fiscal year ended December 31, 2007, filed as part of this Annual Report on Form 40-F.

(d)	Attestation Report of the Registered Public Accounting Firm. The required disclosure is included in the “Auditors’ Report” that accompanies the registrant’s Consolidated Financial Statements for the fiscal year ended December 31, 2007, filed as part of this Annual Report on Form 40-F.

(e)

Changes in Internal Control Over Financial Reporting. During the fiscal year ended December 31, 2007, there were no changes in the registrant’s internal control over financial reporting that have materially affected, or are reasonably likely to materially affect, the registrant’s internal control over financial reporting.

Notices Pursuant to Regulation BTR.

None.

Audit Committee Financial Expert.

The registrant’s board of directors has determined that Mike H. Shaikh, a member of the registrant’s audit committee, qualifies as an “audit committee financial expert” (as such term is defined in Form 40-F). Mr. Shaikh is “independent” as that term in defined in the rules of the New York Stock Exchange.

Code of Ethics

The registrant has adopted a “code of ethics” (as that term is defined in Form 40-F) that applies to its principal executive officer, principal financial officer, principal accounting officer or controller, and persons performing similar functions.

The Code of Ethics is available for viewing on the registrant’s website at www.providentenergy.com.

In connection with the registrant’s listing on the New York Stock Exchange, the Code of Ethics was amended in March 2006 to reflect the New York Stock Exchange’s guidelines for codes of ethics. Since the adoption of the Code of Ethics, other than such amendment, there have not been any amendments to the Code of Ethics or waivers, including implicit waivers, from any provision of the Code of Ethics.

Principal Accountant Fees and Services.

The required tabular disclosure is included under the heading Audit Committee Information—External Auditor Service Fees in the Renewal Annual Information Form, filed as part of this Annual Report on Form 40-F.

Audit Fees.

Audit fees consist of fees for the audit of the registrant’s annual financial statements or services that are normally provided in connection with statutory and regulatory filings or engagements.

Fees for audit services totaled approximately $2.9 million in 2007 and approximately $2.7 million in 2006, including fees associated with the annual audit, the reviews of the Trust’s quarterly reports, statutory audits and regulatory filings. These fees include approximately $1.7 million in 2007 and $1.5 million in 2006 directly related to U.S. operations.

Audit-Related Fees.

Audit-related fees consist of fees for assurance and related services that are reasonably related to the performance of the audit or review of the registrant’s financial statements

and are not reported as Audit Fees. Fees for audit-related services totaled approximately $0.6 million in 2007 and approximately $1.2 million in 2006. Audit related services include consultations concerning documents filed with respect to audits in connection with proposed or completed acquisitions and for 2007 included work related to BreitBurn Energy Partners L.P.

Tax Fees.

Tax fees consist of fees for tax compliance services, tax advice and tax planning. During fiscal 2007 and 2006, the services provided in this category included assistance and advice in relation to the preparation of corporate tax returns. Fees for tax services totaled approximately $0.7 million in 2007 and approximately $1.2 million in 2006.

All Other Fees.

Fees for all other services totaled approximately $0.2 million in 2007 for miscellaneous consulting services.

Pre-Approval Policies and Procedures.

(a)

All proposed services or the fees payable in connection with such services that have not already been pre-approved must be pre-approved by either the audit committee or pursuant to Delegated Authority (as defined below). Subject to the next paragraph, the audit committee has delegated authority to the chairman of the audit committee to pre-approve the provision of permitted services by PricewaterhouseCoopers LLP and not otherwise pre-approved by the full audit committee, including the fees and terms of the proposed services ("Delegated Authority"). All pre-approvals granted pursuant to Delegated Authority must be presented by the chairman to the full audit committee at its next meeting.

The fees payable in connection with any particular service to be provided by PricewaterhouseCoopers LLP that has been pre-approved pursuant to Delegated Authority may not exceed Cdn$100,000. Amounts exceeding Cdn$100,000 must be pre-approved by the full audit committee.

Prohibited services may not be pre-approved by the audit committee or pursuant to Delegated Authority.

(b)

Of the fees reported in this Annual Report on Form 40-F under the heading “Principal Accountant Fees and Services” (including the disclosure reported under the heading Audit Committee Information—External Auditor Service Fees in the Renewal Annual Information Form filed as part of this Annual Report on Form 40-F), nil of the fees billed by PricewaterhouseCoopers LLP were approved by the audit committee of the registrant pursuant to the de minimis exception provided by Section (c)(7)(i)(C) of Rule 2-01 of Regulation S-X.

Off-Balance Sheet Arrangements.

The registrant does not have any off-balance sheet financing arrangements that have or are reasonably likely to have an effect on its results of operations or financial condition.

Tabular Disclosure of Contractual Obligations.
Consolidated					Payment Due By Period
$Millions	Total		Less than			1– 3		3– 5	More than
			1 year			years	years		5 years
Long-term debt – revolving term credit facilities(1)	$	1,483.4	$	76.1	$	1,407.3	$	-	$	-
Long-term debt – convertible debentures		343.0		39.1		58.0		245.9		-
Operating lease obligations		224.7		20.4		39.6		34.4		130.3
Total	$	2,051.1	$	135.6	$	1,504.9	$	280.3	$	130.3

1) The terms of the Canadian credit facility have a revolving three year period expiring on May 30, 2010. Provident can extend the revolving period by an additional year, no earlier than 90 days and no later than 30 days prior to the end of the first year of the applicable three year revolving period. If the lenders do not extend the revolving period, or Provident chooses not to extend, the credit facility will be terminated and the loan balance will become due and payable in full on the maturity date. Management intends to extend the revolving period beyond the current maturity date.

Identification of the Audit Committee.

The registrant has a separately-designated standing audit committee established in accordance with Section 3(a)(58)(A) of the Exchange Act. The members of the audit committee are: Mike H. Shaikh, Hugh A. Ferguson and Bruce R. Libin.

Disclosure Pursuant to the Requirements of the New York Stock Exchange.

Presiding Director at Meetings of Non-Management Directors

The registrant schedules regular executive sessions in which the registrant's "non-management directors"(as that term is defined in the rules of the New York Stock Exchange) meet without management participation. Mr. John Zaozirny serves as the presiding director (the "Presiding Director") at such sessions. Each of the registrant's non-management directors is "unrelated" as such term is used in the rules of the Toronto Stock Exchange. The Provident Board of Directors is responsible for determining whether or not each director is independent. In making this determination, the Board has adopted the definition of "independence" as set out in Section 1.4 of Multilateral Instrument 52-110 Audit Committees ("MI-51-110"). In applying this definition, the Board considers all relationships of the directors with Provident, including business, family and other relationships. Provident's Board of Directors also determines whether each member of Provident's Audit Committee is independent pursuant to Sections 1.4 and 1.5 of MI 52-110 and Rule 10A-3 of the Securities Exchange Act of 1934. Provident's Board of Directors has not adopted the director independence standards contained in Section 303A.02 of the NYSE's Listed Company Manual.

Communication with Non-Management Directors

Shareholders may send communications to the registrant's non-management directors by writing to the Presiding Director, c/o Lynn M. Rannelli, Assistant Corporate Secretary, Provident Energy Ltd., 2100, 250 2nd Steet S.W., Calgary, Alberta, Canada T2P 0H3.

Communications will be referred to the Presiding Director for appropriate action. The status of all outstanding concerns addressed to the Presiding Director will be reported to the board of directors as appropriate.

Corporate Governance Guidelines

According to Section 303A.09 of the NYSE Listed Company Manual, a listed company must adopt and disclose a set of corporate governance guidelines with respect to specified topics. Such guidelines are required to be posted on the listed company's website. The registrant operates under corporate governance principles that are consistent with the requirements of Section 303A.09 of the NYSE Listed Company Manual, many of which are described under the heading "Statement of Corporate Governance Practices" in the registrant's Information Circular in connection with its 2006 Annual Meeting. However, the registrant has not codified its corporate governance principles into formal guidelines in order to post them on its website.

Board Committee Mandates

The Mandates of the registrant's audit committee, human resources and compensation committee, and nominating and corporate governance committee are each available for viewing on the registrant's website at www.providentenergy.com, and are available in print to any unitholder who requests them. Requests for copies of these documents should be made by contacting: Lynn M. Rannelli, Assistant Corporate Secretary, Provident Energy Ltd., 2100, 250 – 2 Street S.W., Calgary, Alberta, Canada T2P 0H3. Alternatively, requests for these documents may be made by contacting the registrant's Corporate Secretarial Department at (403) 296-2233 (Fax: (403) 205-3539).

UNDERTAKING AND CONSENT TO SERVICE OF PROCESS

A. Undertaking.

The registrant undertakes to make available, in person or by telephone, representatives to respond to inquiries made by the Securities and Exchange Commission (the “Commission”) staff, and to furnish promptly, when requested to do so by the Commission staff, information relating to: the securities registered pursuant to Form 40-F; the securities in relation to which the obligation to file an annual report on Form 40-F arises; or transactions in said securities.

B. Consent to Service of Process.

The Company has previously filed a Form F-X in connection with the class of securities in relation to which the obligation to file this report arises.

Any change to the name or address of the agent for service of process of the registrant shall be communicated promptly to the Securities and Exchange Commission by an amendment to the Form F-X referencing the file number of the relevant registration statement.

SIGNATURES

Pursuant to the requirements of the Exchange Act, the registrant certifies that it meets all of the requirements for filing on Form 40-F and has duly caused this annual report to be signed on its behalf by the undersigned, thereunto duly authorized, on March 27, 2008.

	PROVIDENT ENERGY TRUST By: Provident Energy Ltd.

	By:	/s/ Thomas W. Buchanan
		Name:Thomas W. Buchanan
		Title:President and Chief Executive Officer

EXHIBIT INDEX

Exhibit Description

99.1	Certification of Chief Executive Officer pursuant to Rule 13a-14(a) or 15d-14 of the Securities Exchange Act of 1934

99.2	Certification of Chief Financial Officer pursuant to Rule 13a-14(a) or 15d-14 of the Securities Exchange Act of 1934

99.3	Certification of Chief Executive Officer pursuant to 18 U.S.C. Section 1350

99.4	Certification of Chief Financial Officer pursuant to 18 U.S.C. Section 1350

99.5	Consent of PricewaterhouseCoopers LLP

99.6	Consent of McDaniel & Associates Consultants Ltd.

99.7	Consent of Netherland, Sewell & Associates Inc.

99.8	Consent of AJM Petroleum Consultants

99.9	Consent of Data & Consulting Services Division of Schlumberger Technology Corporation

	(b)	Management’s Discussion and Analysis of Financial Condition; and Results of Operations for the fiscal year ended December 31, 2007; and

	(c)	Consolidated Financial Statements for the fiscal year ended December 31, 2007 (Note 19 to the Consolidated Financial Statements relates to United States Accounting Principles and Reporting (U.S. GAAP).