40-F 1 d40f.htm PROVIDENT ENERGY TRUST FORM 40-F Provident Energy Trust Form 40-F
  SECURITIES AND EXCHANGE COMMISSION 
Washington, D.C. 20549 
 
FORM 40-F 
(Check one)
o
 REGISTRATION STATEMENT PURSUANT TO SECTION 12 OF THE SECURITIES EXCHANGE ACT OF 1934 
 OR 
þ
  ANNUAL REPORT PURSUANT TO SECTION 13(A) OR 15(D) OF THE SECURITIES EXCHANGE ACT OF 1934
 
For the fiscal year ended December 31, 2006
 
Commission file number 1-15196
PROVIDENT ENERGY TRUST
  (Exact name of Registrant as specified in its charter)
 
Alberta, Canada
  
1311
  
Not applicable
(Province or other jurisdiction of
incorporation or organization)
 
(Primary Standard Industrial
Classification Code Number
(if applicable))
(I.R.S. Employer
Identification Number
(if Applicable))
 
Suite 800, 112 - 4th Avenue S.W., Calgary, Alberta, Canada T2P 0H3
(403) 296-2233
(Address and telephone number of Registrant’s principal executive offices) 
 
Andrews Kurth LLP
600 Travis
Suite 4200
Houston, Texas 77002
(Name, Address (Including Zip Code) and Telephone Number
(Including Area Code) of Agent For Service in the United States)
 
Securities registered or to be registered pursuant to Section 12(b) of the Act.
 
Title of each class
Trust Units
Name of each exchange on which registered
New York Stock Exchange
 
Securities registered or to be registered pursuant to Section 12(g) of the Act. None
Securities for which there is a reporting obligation pursuant to Section 15(d) of the Act. None
For annual reports, indicate by check mark the information filed with this Form:
 
þ
 Annual information form
þ
 Audited annual financial statements
 
Indicate the number of outstanding shares of each of the issuer’s classes of capital or common stock as of the close of the period covered by the annual report:

Trust Units outstanding at December 31, 2006: 188,978,637
 
Indicate by check mark whether the registrant by filing the information contained in this Form is also thereby furnishing the information to the Commission pursuant to Rule 12g3-2(b) under the Securities Exchange Act of 1934 (the “Exchange Act”). If “Yes” is marked, indicate the file number assigned to the registrant in connection with such rule.
 
 Yes
o
 No
þ
 
Indicate by check mark whether the registrant: (1) has filed all reports required to be filed by Section 13 or 15(d) of the Exchange Act during the preceding 12 months (or for such shorter period that the registrant was required to file such reports); and (2) has been subject to such filing requirements for the past 90 days.
 
 Yes
þ
 No
o
 
FORM 40-F
 

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, 2006, an evaluation of the effectiveness of the registrant’s “disclosure controls and procedures” (as such term is defined in Rules 13a-15(e) and 15d-15(e) of the Securities Exchange Act of 1934, as amended (the “Exchange Act”)) was carried out by the Chief Executive Officer (“CEO”) and Chief Financial Officer (“CFO”) of Provident Energy Ltd., who also perform such functions for the registrant. Based upon that evaluation, the CEO and CFO have concluded that as of the end of that fiscal year, the registrant’s disclosure controls and procedures are effective to ensure that information required to be disclosed by the registrant in reports that it files or submits under the Exchange Act is (i) recorded, processed, summarized and reported within the time periods specified in Securities and Exchange Commission rules and forms and (ii) accumulated and communicated to the registrant’s management, including its principal executive officer and principal financial officer, to allow timely decisions regarding required disclosure.

It should be noted that while the CEO and CFO believe that the registrant’s disclosure controls and procedures provide a reasonable level of assurance that they are effective, they do not expect that the registrant’s disclosure controls and procedures or internal control over financial reporting will prevent all errors and fraud. A control system, no matter how well conceived or operated, can provide only reasonable, not absolute, assurance that the objectives of the control system are met.

(c)
Changes in Internal Control Over Financial Reporting. During the fiscal year ended December 31, 2006, there were no changes in the registrant’s internal control over financial reporting that have materially affected, or are reasonably likely to materially affect, the registrant’s internal control over financial reporting.

Notices Pursuant to Regulation BTR. 

None.

Audit Committee Financial Expert.

The registrant’s board of directors has determined that Mike H. Shaikh, a member of the registrant’s audit committee, qualifies as an “audit committee financial expert” (as such term is defined in Form 40-F).
 
Code of Ethics.

The registrant has adopted a “code of ethics” (as that term is defined in Form 40-F) that applies to its principal executive officer, principal financial officer, principal accounting officer or controller, and persons performing similar functions.
 
The Code of Ethics is available for viewing on the registrant’s website at www.providentenergy.com.
 
Since the adoption of the Code of Ethics, there have not been any amendments to the Code of Ethics or waivers, including implicit waivers, from any provision of the Code of Ethics.
 
Principal Accountant Fees and Services.
 
A table summarizing fees is included under the heading Audit Committee Information in the Renewal Annual Information Form included as part of this form.
 
Audit Fees. Audit fees consist of fees for the audit of the registrant’s annual financial statements or services that are normally provided in connection with statutory and regulatory filings or engagements.
 
Audit-Related Fees. Audit-related fees consist of fees for assurance and related services that are reasonably related to the performance of the audit or review of the registrant’s financial statements and are not reported as Audit Fees. During fiscal 2004 and 2003, the services provided in this category included due diligence reviews in connection with acquisitions, research of accounting and audit-related issues, review of reserves disclosure and the completion of audits required by contracts to which the registrant is a party.
 
Tax Fees. Tax fees consist of fees for tax compliance services, tax advice and tax planning. During fiscal 2005 and 2006, the services provided in this category included assistance and advice in relation to the preparation of corporate income tax returns.
 
All Other Fees. Not applicable.
 
Pre-Approval Policies and Procedures.
 
(a)
All proposed services or the fees payable in connection with such services that have not already been pre-approved must be pre-approved by either the audit committee or pursuant to Delegated Authority (as defined below). Subject to the next paragraph, the audit committee has delegated authority to the chairman of the audit committee to pre-approve the provision of permitted services by PricewaterhouseCoopers LLP and not otherwise pre-approved by the full audit committee, including the fees and terms of the proposed services ("Delegated Authority"). All pre-approvals granted pursuant to Delegated Authority must be presented by the chairman to the full audit committee at its next meeting.
 
 
The fees payable in connection with any particular service to be provided by PricewaterhouseCoopers LLP that has been pre-approved pursuant to Delegated Authority may not exceed Cdn$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”, nil of the fees billed by PricewaterhouseCoopers LLP were approved by the audit committee of the registrant pursuant to the de minimus exception provided by Section (c)(7)(i)(C) of Rule 2-01 of Regulation S-X.
 
Off-Balance Sheet Arrangements.
 
There are no off balance sheet arrangements.
 
Tabular Disclosure of Contractual Obligations.
 
     
(CDN$ millions)
 
Payment due by period
 Contractual Obligations
 Total
Less than 1
Year
1 to 3
Years
3 to 5
Years
More than
5 years
Long-Term Debt Obligations
988.8
-
752.8
142.9
93.1
Capital (Finance) Lease Obligations
-
-
-
-
-
Operating Lease Obligations
196.0
16.6
36.8
27.9
114.7
Purchase Obligations
-
-
-
-
-
Other Long-Term Liabilities Reflected on the Registrant's Balance Sheet under Canadian GAAP
143.7
-
60.7
23.2
59.8
Total
1,328.5
16.6
850.3
194.0
267.6
 

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.
 
 

 
For the year ended December 31, 2006
 

 
March 28, 2007
 
 
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"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;
 
"Accrete" means Accrete Energy Inc., formerly 1101130 Alberta Ltd.;
 
"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;
 
"ARTC" means credits or rebates in respect of Crown royalties, which are paid or credited by the Crown, including those paid or credited under the Alberta Corporate Tax Act, which are commonly known as "Alberta Royalty Tax Credits";
 
"BEC L.P." means BreitBurn Energy Company L.P., a Delaware limited partnership and an indirect subsidiary of the Trust;
 
"BEC L.P. Properties" means the oil and gas properties held by BEC L.P. in the State of California and in the State of Wyoming;
 
"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;
 
"Chamaelo" means Chamaelo Energy Inc., formerly 1100974 Alberta Inc.;
 
"Distributable Cash" means all amounts distributed or to be distributed during any applicable period to Unitholders;
 
"Distribution Record Date" means on or about the 20th day of each calendar month or such other date as may be determined from time to time by the Trustee;
 
"Founders" means Founders Energy Ltd., a predecessor of Provident;
 
"GLJ" means Gilbert Laustsen Jung Associates Ltd., independent petroleum engineers;
 
"Holdings Trust" means Provident Holdings Trust;
 
"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; 
 
"Manager" means Provident Management Corporation, a corporation incorporated under the ABCA;
 
"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;
 
"Olympia" means Olympia Energy Inc.;
 
"Olympia Arrangement" means the plan of arrangement in which the Trust acquired all of the issued and outstanding common shares of Olympia pursuant to an arrangement agreement dated April 6, 2004 among the Trust, Provident, Olympia and Accrete;
 
"Option Plan" means the trust unit option plan of the Trust providing for the issuance of options to acquire Trust Units to employees, officers, directors and consultants of the Trust;
 
"Orcutt Hill Acquisition" means the acquisition by 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.;
 
"Permitted Investments" means: (i) obligations issued or guaranteed by the government of Canada or any province of Canada or any agency or instrumentality thereof; (ii) term deposits, guaranteed investment certificates, certificates of deposit or bankers' acceptances of or guaranteed by any Canadian chartered bank or other financial institutions (including the Trustee and any affiliate of the Trustee) the short-term debt or deposits of which have been rated at least A or the equivalent by Standard & Poor's Corporation, Moody's Investors Service, Inc., Canadian Bond Rating Service Inc. or Dominion Bond Rating Service Limited; and (iii) commercial paper rated at least A or the equivalent by Canadian Bond Rating Service Inc. or Dominion Bond Rating Service Limited, in each case maturing within 180 days after the date of acquisition;
 
"PMI" means Provident Midstream Inc.;
 
"PHC" means Pro Holding Company;
 
"Provident" means Provident Energy Ltd.;
 
"Redwater Acquisition" means the acquisition by Provident of the Redwater natural gas liquids processing business from Williams 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.;
 
"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 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;
 
"Unitholders" means the holders from time to time of the Trust Units;
 
"Viracocha" means Viracocha Energy Inc.; and
 
"Viracocha Arrangement" means the plan of arrangement in which the Trust acquired all of the issued and outstanding common shares of Viracocha pursuant to an arrangement agreement dated April 6, 2004 among the Trust, Provident, Viracocha and Chamaelo.
 
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.
 
 
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.

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
 
 
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 flow before changes in non-cash working capital related to operating activities and site restoration expenditures, as presented in the consolidated financial statements of the Trust. The actual amount of cash that is distributed cannot be assured and future distributions may vary. 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 oil and gas sector. The Trust believes that such terms are useful supplemental measures as they provide investors with information of what cash is available for distribution from the Trust to Unitholders in such periods.
 
This Renewal Annual Information Form and the documents incorporated by reference herein contain forward-looking statements. These statements relate to future events or the Trust's future performance. All statements other than statements of historical fact are forward-looking statements. In some cases, forward-looking statements can be identified by terminology such as "may", "will", "should", "expect", "plan", "anticipate", "believe", "estimate", "predict", "potential", "continue", or the negative of these terms or other comparable terminology. Forward looking statements or information in this 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. These statements are only predictions. Actual events or results may differ materially. 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 these forward-looking statements, as there can be no assurance that the plans, intentions or expectations upon which they are based will occur. By its nature, forward-looking information involves numerous assumptions, known and unknown risks and uncertainties, both general and specific, that contribute to the possibility that the predictions, forecasts, projections and other forward-looking statements will not occur. Forward-looking statements in this 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;
 
·
the performance characteristics of Provident's natural gas midstream, NGL processing and marketing business;
 
·
the growth opportunities associated with the natural gas midstream, NGL processing and marketing business; and
 
·
the nature of contractual arrangements with third parties in respect of Provident's natural gas midstream, NGL processing and marketing business.
 
Although the Trust believes that the expectations reflected in the forward-looking statements are reasonable, there can be no assurance that such expectations will prove to be correct. The Trust can not guarantee future results, levels of activity, performance, or achievements. Moreover, neither the Trust nor any other person assumes responsibility for the accuracy and completeness of the forward-looking statements. Some of the risks and other factors, some of which are beyond the Trust's control, which could cause results to differ materially from those expressed in the forward-looking statements contained in this Annual Information Form and the documents incorporated by reference herein include, but are not limited to:
 
 
·
general economic conditions in Canada, the United States and globally;
 
·
industry conditions 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 proposed taxation of trust distributions;
 
·
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 Annual Information Form.
 
 
Statements relating to "reserves" or "resources" are deemed to be forward-looking statements, as they involve the implied assessment, based on certain estimates and assumptions, that the resources and reserves described can be profitably produced in the future. Readers are cautioned that the foregoing list of factors is not exhaustive. The forward-looking statements contained in this Renewal Annual Information Form and the documents incorporated by reference herein are expressly qualified by this cautionary statement. Subject to the Trust's obligations under applicable securities laws, the Trust is not under any duty to update any of the forward-looking statements after the date of this Renewal Annual Information Form to conform such statements to actual results or to changes in the Trust's expectations.
 
 
 
Provident Energy Trust is an open-end unincorporated investment trust governed by the laws of the Province of Alberta and created pursuant to the Trust Indenture. The head and principal offices of the Trust are located at 800, 112 - 4th Avenue S.W., Calgary, Alberta T2P 0H3. The registered office of the Trust is located at 3700, 400 - 3rd Avenue S.W., Calgary, Alberta T2P 4H2.
 
 
Provident Energy Ltd. is a corporation the common shares of which are wholly-owned by the Trust. Provident was incorporated under the ABCA on January 19, 2001 and was amalgamated with Founders pursuant to a plan of arrangement involving the Trust, Provident and Founders effective March 6, 2001. Provident subsequently amalgamated with Maxx Petroleum Ltd. ("Maxx") effective May 25, 2001 pursuant to a plan of arrangement involving the Trust, Provident and Maxx. Provident was also amalgamated with Richland Petroleum Corporation ("Richland") effective January 16, 2002 pursuant to a plan of arrangement involving the Trust, Provident and Richland. Provident was amalgamated with Provident Management Corporation pursuant to a management internalization transaction involving the Trust, Provident, the Manager and the shareholders of the Manager effective January 17, 2003. Provident was also amalgamated with Olympia and Viracocha on June 1, 2004 pursuant to plans of arrangement involving the Trust, Provident, Viracocha and Olympia. The head and principal offices of Provident are located at 800, 112 - 4th Avenue S.W., Calgary, Alberta T2P 0H3. The registered office of Provident is located at 3700, 400 - 3rd Avenue S.W., Calgary, Alberta T2P 4H2.
 
 
Provident Holdings Trust 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 800, 112 - 4th Avenue S.W., Calgary, Alberta T2P 0H3. The registered office of Holdings Trust is located at 3700, 400 - 3rd Avenue S.W., Calgary, Alberta T2P 4H2.
 
 
Provident Acquisitions L.P. 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 800, 112 - 4th Avenue S.W., Calgary, Alberta T2P 0H3. The registered office of Provident Acquisitions L.P. is located at 3700, 400 - 3rd Avenue S.W., Calgary, Alberta T2P 4H2.
 
 
Provident Midstream L.P. 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 800, 112 - 4th Avenue S.W., Calgary, Alberta T2P 0H3. The registered office of Provident Midstream L.P. is located at 3700, 400 - 3rd Avenue S.W., Calgary, Alberta T2P 4H2.
 
 
Provident Acquisitions Inc. 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 800, 112 - 4th Avenue S.W., Calgary, Alberta T2P 0H3. The registered office of PAI is located at 3700, 400 - 3rd Avenue S.W., Calgary, Alberta T2P 4H2.
 
 
Provident Midstream Inc. 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 800, 112 - 4th Avenue S.W., Calgary, Alberta T2P 0H3. The registered office of PMI is located at 3700, 400 - 3rd Avenue S.W., Calgary, Alberta T2P 4H3.
 
 
Pro Holding Company 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. 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. 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 66 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.
 
 
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.
 


 
 
Cash Flow
 
The Trust indirectly holds interests in petroleum and natural gas properties and the natural gas midstream, NGL processing and marketing business through Provident and its various subsidiaries. Cash flow from the petroleum and natural gas properties flows from Provident and the Trust's various subsidiaries to the Trust by way of royalty payments and interest payments and principal repayments on notes issued by the Trust from time to time. Cash flow from the natural gas midstream, NGL processing and marketing business flows from Provident to the Trust and the Trust's various subsidiaries by way of interest payments and principal repayments on notes issued by the Trust. Distributable income generated by the royalty payments, interest payments and principal repayments is then distributed monthly to the Unitholders.
 
Under the terms of the Trust Indenture the Trust is also entitled to (i) invest in securities of Provident from time to time; (ii) acquire royalties; (iii) temporarily hold cash and Permitted Investments for the purposes of paying the expenses and liabilities of the Trust and paying amounts payable by the Trust in connection with the redemption of any Trust Units and making distributions to Unitholders; (iv) acquire or invest in Subsequent Investments; and (v) pay the costs, fees and expenses associated with or incidental to the foregoing.
 
Cash Distributions
 
The Trustee intends to make cash distributions on or about the 15th day of each month to Unitholders of record on the immediately preceding Distribution Record Date in amounts equal to all of the interest, royalty and dividend income of the Trust, net of the Trust's administrative expenses. In addition, Unitholders may, at the discretion of the Trustee, receive distributions in respect of repayments of principal made by Provident to the Trust on notes issued by the Trust from time to time. It is anticipated however, that the Trust will reinvest a portion of the repayments of principal on the notes outstanding to enable Provident to make capital expenditures to develop or acquire additional oil and natural gas properties to enhance cash flow from operations.
 
The Trust seeks to provide a stable stream of cash distributions, subject to, among other things, fluctuations in the quantity of petroleum and natural gas substances produced, prices received for that production, hedging contract receipts and payments, taxes, direct expenses of the Trust, reclamation fund contributions, fluctuations in the demand for NGLs and natural gas, competition from other gas processing plants, operational matters and hazards related to the natural gas midstream, NGL processing and marketing business, capital expenditures, debt servicing, operating costs, debt service charges and general and administrative expenses as determined necessary by Provident on behalf of the Trust.
 
Trust Units
 
An unlimited number of Trust Units may be created and issued pursuant to the Trust Indenture. Each Trust Unit represents an equal fractional undivided beneficial interest in any distribution from the Trust (whether of net income, net realized capital gains or other amounts) and in any net assets of the Trust in the event of termination or winding-up of the Trust. All Trust Units outstanding from time to time shall be entitled to an equal share of any distributions from, and in any net assets of, the Trust in the event of the termination or winding-up of the Trust. All Trust Units rank among themselves equally and rateably without discrimination, preference or priority. Each Trust Unit is transferable, is not subject to any conversion or pre-emptive rights and entitles the holder thereof to require the Trust to redeem any or all of the Trust Units held by such holder and to one vote at all meetings of holders of Trust Units for each Trust Unit held. Holders of Trust Units shall not be subject to any liability in contract or tort or of any other kind in connection with the assets, obligations or affairs of the Trust or with respect to any acts performed by the Trustee or any other person pursuant to the Trust Indenture.
 
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, 2007, there was $25.7 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. 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, 2007, 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, 2007, 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, 2007, there was $150.0 million aggregate principal amount of Supplemental 6.5 Percent Debentures outstanding.
 
Meetings of Unitholders
 
Meetings of holders of Trust Units will be called and held annually for, among other things, the election of the directors of Provident and the appointment of the auditors of the Trust. The Trust Indenture provides that meetings of Unitholders must be called and held for, among other matters, the election or removal of the Trustee, the appointment or removal of the auditors of the Trust, the approval of certain amendments to the Trust Indenture, to assign, transfer or dispose of royalties as an entirety or substantially as an entirety, and the commencement of winding-up the affairs of the Trust.
 
Unitholders may attend and vote at all meetings of Unitholders either in person or by proxy and a proxy holder need not be a holder of Trust Units. Two persons present in person or represented by proxy and representing in the aggregate at least 5 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 28, 2007. As of March 19, 2007, there were 1,631,918 options granted and outstanding under the Option Plan.
 
Premium Distribution, Distribution Reinvestment and Optional Unit Purchase Plan
 
The Trust has implemented a premium distribution, distribution reinvestment and optional unit purchase plan (the "DRIP") to provide holders of Trust Units with a means to automatically reinvest sums received on account of distributions on Trust Units. Provident reserves the right to prorate the participation in the DRIP to manage the amount of cash reinvested in the Trust and the Trust Units issued under the DRIP. Computershare Trust Company of Canada, as plan agent, may at the election of a participant (a) purchase Trust Units with the cash distributions at 95 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.
 
Taxation of the Trust
 
The Trust is a unit trust and a mutual fund trust for purposes of the Tax Act. As such, until the proposals made by the Federal Minister of Finance on October 31, 2006 (the "October 31 Proposals") as reflected in the Notice of Ways and Means Motion released on March 27, 2007 become law, the Trust is only taxable on any taxable income not allocated to Unitholders.
 
Pursuant to the October 31 Proposals, 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 the Trust level at rates of tax comparable to the combined federal and provincial tax rates. Returns of capital generally are (and under the October 31 Proposals 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. See "Risk Factors - Changes in Legislation".
 
Limitation on Non-Resident Trust Unitholders
 
In accordance with the Trust Indenture, in order to ensure the maintenance of the Trust's "mutual fund trust" status, Provident will: (i) prior to the consummation of any transaction involving the acquisition by the Trust of any Subsequent Investment; (ii) prior to any material modification to the Trust Fund other than as contemplated by subclause (i); (iii) promptly following any proposed amendment to paragraph 132(7)(a) of the Tax Act (which provision relates to the level of "taxable Canadian property") or the publication of any administrative bulletin or other notice of interpretation relating to the interpretation or application of such section; or (iv) otherwise at any time when requested by the Trustee, obtain an opinion of counsel confirming whether the Trust is, at the date thereof and following such transaction or event (which in the case of (iii) shall mean the coming into effect of the amendment or change of interpretation), entitled to rely on paragraph 132(7)(a) of the Tax Act (or any successor provision thereto) for purposes of qualifying as a "mutual fund trust" under the Tax Act.
 
If at any time the board of directors of Provident determines, in its sole discretion, or becomes aware that the Trust's ability to continue to rely on paragraph 132(7)(a) of the Tax Act (or any successor provision thereto) for purposes of qualifying as a "mutual fund trust" thereunder is in jeopardy, then forthwith after such determination Provident will take such steps as are necessary or desirable to ensure that the Trust is not maintained primarily for the benefit of Non-Residents.
 
Provident may, at any time and from time to time, in its sole discretion, request that the Trustee make reasonable efforts, as practicable in the circumstances, to obtain declarations as to beneficial ownership, perform residency searches of shareholder and beneficial shareholder mailing address lists and take such other steps specified by Provident, at the cost of the Trust, to determine or estimate as best possible the residence of the beneficial owners of Trust Units.
 
If at any time the board of directors of Provident, in its sole discretion, determines that it is in the best interest of the Trust, Provident, notwithstanding the ability of the Trust to continue to rely on subsection 132(7)(a) of the Tax Act for the purpose of qualifying as a "mutual fund trust" under the Tax Act, may (i) require the Trustee to refuse to accept a subscription for Trust Units from, or issue or register a transfer of Trust Units to, a person unless the person provides a declaration to Provident that the Trust Units to be issued or transferred to such person will not when issued or transferred be beneficially owned by a Non-Resident; (ii) to the extent practicable in the circumstances, send a notice to registered holders of Trust Units which are beneficially owned by Non-Residents, chosen in inverse order to the order of acquisition or registration of such Trust Units beneficially owned by Non-Residents or in such other manner as Provident may consider equitable and practicable, requiring them to sell their Trust Units which are beneficially owned by Non-Residents or a specified portion thereof within a specified period of not less than 60 days.
 
If the Unitholders receiving such notice have not sold the specified number of such Trust Units or provided Provident with satisfactory evidence that such Trust Units are not beneficially owned by Non-Residents within such period, Provident may, on behalf of such registered Unitholder, sell such Trust Units and, in the interim, suspend the voting and distribution rights attached to such Trust Units and make any distribution in respect of such Trust Units by depositing such amount in a separate bank account in a Canadian chartered bank (net of any applicable taxes).
 
Any sale shall be made on any stock exchange on which the Trust Units are then listed and, upon such sale, the affected holders shall cease to be holders of Trust Units so disposed of and their rights shall be limited to receiving the net proceeds of sale, and any distribution in respect thereof deposited as aforesaid, net of applicable taxes and costs of sale, upon surrender of the certificates representing such Trust Units; (iii) delist the Trust Units from any non-Canadian stock exchange; and (iv) take such other actions as the board of directors of Provident determines, in its sole discretion, are appropriate in the circumstances that will reduce or limit the number of Trust Units held by Non-Residents to ensure that the Trust is not maintained primarily for the benefit of Non-Residents.
 
Generally, a trust cannot qualify as a "mutual fund trust" for the purposes of the Tax Act if it is established or is being maintained primarily for the benefit of non-residents. Although not without uncertainty, this is generally accepted to exist in most situations where Non-Resident holders own significantly in excess of 50 percent of the aggregate number of Trust Units issued and outstanding. However, there is currently an exception to the non-resident ownership restriction in paragraph 132(7)(a) of the Tax Act where not more than 10 percent of the trust's property has at any time consisted of "taxable Canadian property".
 
 
Redemption Right
 
Trust Units are redeemable at any time on demand by the holders thereof upon delivery to the Trust of the certificate or certificates representing such Trust Units, accompanied by a duly completed and properly executed notice requesting redemption. Upon receipt of the redemption request by the Trust, the holder thereof shall only be entitled to receive a price per Trust Unit (the "Market Redemption Price") equal to the lesser of: (i) 90 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. 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;
 
·
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.

 
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.
 
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 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 Acquisitions L.P. holds certain southeast Alberta properties. 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 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.
 
 
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 the remaining 99.9999 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.
 
 
PMI holds the Redwater Midstream NGL Assets. The Trust receives cash flow generated by PMI by way of interest and principal payments on debt owing from PMI to the Trust.
 
 
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 66 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.
 
 
BEC L.P. holds certain of the BEC L.P. Properties 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.
 
 
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. 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 66 percent of the outstanding partnership interests in BreitBurn MLP. The co-founders and co-chief executive officers of BEC L.P. hold approximately 3 percent of the partnership interests in BreitBurn MLP, with the public holding the remaining 31 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.

 
The following information describes the development of the business of the Trust and its material subsidiaries over the last three completed financial years.
 
On January 12, 2004, the Trust announced the appointment of Dr. Robert W. Mitchell to the Board of Directors of Provident.
 
On February 4, 2004, the Trust completed a public offering of 4,500,000 Trust Units for gross proceeds of $50.4 million. The net proceeds were used to fund a portion of the Trust's 2004 capital expenditure program and to repay debt.
 
On April 6, 2004, the Trust, Provident, Olympia and Accrete entered into an arrangement agreement providing for the acquisition by the Trust of all of the issued and outstanding common shares of Olympia pursuant to the Olympia Arrangement. In connection with the Olympia Arrangement, certain exploration and development properties of Olympia were transferred to Accrete, a newly created company, the shares of which were distributed to Olympia's shareholders under the Olympia Arrangement. On May 27, 2004, shareholders of Olympia approved the Olympia Arrangement. On June 1, 2004, the Trust, Provident, Olympia and Accrete completed the Olympia Arrangement. Provident and Olympia were then amalgamated and continued as Provident Energy Ltd.
 
On April 6, 2004, the Trust, Provident, Viracocha and Chamaelo entered into an arrangement agreement providing for the acquisition by the Trust of all of the issued and outstanding common shares of Viracocha pursuant to the Viracocha Arrangement. In connection with the Viracocha Arrangement, certain exploration and development properties of Viracocha in Alberta were transferred to Chamaelo, a newly created company, the shares of which were distributed to Viracocha's shareholders under the Viracocha Arrangement. On May 27, 2004, shareholders of Viracocha approved the Viracocha Arrangement. On June 1, 2004, the Trust, Provident, Viracocha and Chamaelo completed the Viracocha Arrangement. Provident and Viracocha were then amalgamated and continued as Provident Energy Ltd.
 
On June 15, 2004, the Trust entered into an agreement and plan of merger among BreitBurn, a California limited liability company, Pro GP Corp., a Delaware corporation and wholly-owned indirect subsidiary of the Trust, Pro LP Corp., a Delaware corporation and wholly-owned indirect subsidiary of the Trust and BB Merger LLC ("Acquisition LLC"), a Delaware limited liability company and wholly-owned indirect subsidiary of the Trust, pursuant to which the Trust acquired all of the issued and outstanding shares of BreitBurn, for an aggregate purchase price of $155.0 million in cash and the assumption of approximately $35.0 million of working capital deficiency and financial obligations of BreitBurn, subject to certain adjustments. Under the terms of the BreitBurn agreement, BreitBurn and Acquisition LLC were merged and BreitBurn was converted into BEC L.P., a Delaware limited partnership. The BreitBurn Acquisition was completed on June 15, 2004 and resulted in the Trust indirectly holding 92 percent of the outstanding partnership interests of BEC L.P. as of that date, with the remaining 8 percent of the outstanding partnership interests of BEC L.P. retained by BreitBurn's co-founders and co-chief executive officers for an aggregate purchase price of $13.7 million.
 
In connection with the BreitBurn Acquisition, the Trust completed a public offering on July 6, 2004 of 13,100,000 Trust Units and $50.0 million aggregate principal amount of 8 Percent Debentures for gross proceeds of $186.2 million. The net proceeds from the offering were used to fund the BreitBurn Acquisition, to fund the Trust's capital expenditure program and for general corporate purposes.
 
On September 13, 2004, BEC L.P., entered into a purchase and sale agreement with an arm's length third party vendor pursuant to which BEC L.P. agreed to purchase the Orcutt Hill Properties, consisting of certain oil and natural gas producing properties, related interests and 5,000 acres of surface acreage situated in the Orcutt Hill Oil Field and located in Santa Barbara County, California for a purchase price of US$45.0 million subject to adjustment. The Orcutt Hill Acquisition was completed on October 4, 2004.
 
In connection with the Orcutt Hill Acquisition, the Trust completed a public offering on October 4, 2004 of 11,480,000 Trust Units for gross proceeds of $125.7 million. The net proceeds from the offering were used to fund the Orcutt Hill Acquisition, to fund the Trust's capital expenditure program and for general corporate purposes.
 
On February 9, 2005, 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 EnCana Oil & Gas Partnership, an affiliate of EnCana Corporation, to provide rail offloading and terminalling services for condensate to be used as a heavy oil diluent. A new condensate offloading facility 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 EnCana Oil & Gas Partnership 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.
 
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 will be responsible for overseeing corporate functions at Provident, including finance, strategy, planning, business development, risk management, and communications. On March 28, 2006, Mr. Holm was appointed Corporate Secretary.
 
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.

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 was 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).
 
Provident has estimated that the Rainbow Assets have approximately 22.2 million barrels of oil equivalent of proved plus probable reserves effective June 1, 2006.
 
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, 2007, 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." The Trust owns approximately 96 percent of the general partner of BreitBurn MLP (which holds 2 percent of the partnership interests in BreitBurn MLP) and approximately 66 percent of the limited partnership units of BreitBurn MLP.
 
On October 31, 2006, the federal Finance Minister announced the October 31 Proposals to apply a tax at the trust level on distributions of certain income from publicly traded mutual fund trusts at rates of tax comparable to the combined federal and provincial corporate tax and to treat such distributions as dividends to the Unitholders. The Finance Minister said existing trusts would have a four year transition period and would not be subject to the new rules until 2011 (provided the Trust only experiences "normal growth" and no "undue expansion" before then). On December 21, 2006, the Finance Minister released draft legislation to implement the proposal. See "General Risk Factors - Changes in Legislation" for further discussion of the October 31 Proposals.
 
 
Provident's strategy is focused on achieving a consistent level of monthly cash distributions to the Unitholders. To this end, Provident pursues a balanced portfolio strategy that incorporates the integration of the oil and gas production business and the natural gas midstream, NGL processing and marketing business. This balanced portfolio extends the economic life of the Trust, assists with the stability of cash flows and provides Provident access to a broader range of opportunities across the energy value chain.
 
With respect to the oil and gas production business, Provident is focused on the acquisition, development, exploitation, production and marketing of crude oil and natural gas. Provident's operations are currently located in six core regions in the Western Canadian Sedimentary basin and in the States of California and Wyoming. In management's opinion, these areas generally offer low to medium risk development potential and a well developed operational infrastructure, 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.
 
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.
 
 
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 hedging program designed to protect a portion of its cash flow in order to support continued unitholder distributions, capital programs and bank financing.
 
During 2006 for the oil and gas business units, Provident paid $5.7 million ($0.97 per barrel) to settle various crude oil hedge contracts. Provident received $7.6 million ($0.25 per gj), to settle various natural gas hedge contracts resulting in a combined net gain total of $1.9 million or $0.16 per boe.
 
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).
 
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 effectively mitigate commodity price risk related to its NGL production business up to five years into the future.
 
In 2006, Provident paid $15.4 million to settle various midstream hedge contracts.
 
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 6 percent appreciation of the Canadian dollar relative to the U.S. dollar in 2006. Provident's strategy manages the exposure it has to fluctuations in the U.S./Canadian dollar exchange rate when the underlying commodity price is based upon a U.S. index price. Provident may also use derivative products that provide for insurance against a stronger Canadian dollar, while allowing it to participate if the currency weakens relative to the U.S. dollar.
 
The derivative hedging contracts in place at December 31, 2006 are summarized in the following tables:
 
 
COGP 
   
 Volume
   
Year
Product
(Buy)
Sell
Terms
Effective Period
2007
Crude Oil
750
Bpd
Participating Swap US $60.00 per bbl (62 percent above the floor price)
January 1 - December 31
 
 
750
Bpd
Puts US $60.00 per bbl
January 1 - December 31
 
Natural Gas
2,500
Gjpd
Participating Swap Cdn $6.50 per gj (65 percent above the floor price)
January 1 - August 31
 
 
2,000
Gjpd
Participating Swap Cdn $6.50 per gj (max to 100 percent above the floor price)
January 1 - August 31
 
 
5,000
Gjpd
Participating Swap Cdn $7.00 per gj (max to 82 percent above the floor price)
January 1 - March 31
 
 
1,500
Gjpd
Participating Swap Cdn $7.00 per gj (max to 80 percent above the floor price)
January 1 - March 31,
November 1 - December 31
 
 
4,000
Gjpd
Participating Swap Cdn $6.44 per gj (max to 100 percent above the floor price)
April 1 - August 31
 
 
1,500
Gjpd
Participating Swap Cdn $6.50 per gj (max to 61 percent above the floor price)
April 1 - August 31
 
 
3,000
Gjpd
Participating Swap Cdn $6.33 per gj (max to 100 percent above the floor price)
April 1 - October 31
 
 
3,000
Gjpd
Participating Swap Cdn $6.33 per gj (max to 90 percent above the floor price)
April 1 - October 31
 
 
6,000
Gjpd
Participating Swap Cdn $6.30 per gj (max to 95 percent above the floor price)
April 1 - October 31
 
 
2,000
Gjpd
Participating Swap Cdn $6.13 per gj (max to 68 percent above the floor price)
April 1 - October 31
 
 
1,000
Gjpd
Participating Swap Cdn $6.00 per gj (max to 66 percent above the floor price)
April 1 - October 31
 
 
6,500
Gjpd
Costless Collar Cdn $6.31 floor, Cdn $12.93 ceiling
January 1 - March 31
 
 
7,500
Gjpd
Costless Collar Cdn $6.42 floor, Cdn $9.63 ceiling
January 1 - August 31
 
 
4,000
Gjpd
Costless Collar Cdn $6.75 floor, Cdn $8.56 ceiling
April 1 - August 31
 
 
5,000
Gjpd
Puts Cdn $6.85 per gj
January 1 - December 31
 
 
2,000
Gjpd
Puts Cdn $6.75 per gj
January 1 - March 31
 
 
9,500
Gjpd
Puts Cdn $6.89 per gj
January 1 - March 31,
November 1 - December 31
 
 
4,000
Gjpd
Puts Cdn $6.75 per gj
November 1 - December 31
 
USOGP 
   
Volume  
    
 Year
 Product
(Buy) 
 Sell
Terms
Effective Period
2007
Crude Oil
250
Bpd
Puts US $60.00 per bbl
January 1 - December 31
 
 
250
Bpd
Participating Swap US $55.00 per bbl (max to 84 percent above the floor price)
January 1 - December 31
 
 
3,500
Bpd
US $67.84 per bbl
January 1 - June 30
 
 
2,650
Bpd
US $68.44 per bbl
July 1 - December 31
 
 
250
Bpd
Costless Collar US $66.00 floor, US $69.25 ceiling
July 1 - December 31
 
 
250
Bpd
Costless Collar US $66.00 floor, US $71.50 ceiling
July 1 - December 31
2008
Crude Oil
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
 
 
2,500
Bpd
Participating Swap US $60.00 per bbl (max to 53.3 percent above the floor price)
July 1 - September 31
 
 
4,500
Bpd
Participating Swap US $60.00 per bbl (avg to 56 percent above the floor price)
October 1 - December 31
2009
Crude Oil
500
Bpd
Participating Swap US $60.00 per bbl (max to 55.5 percent above the floor price)
January 1 - September 30
 
 
2,000
Bpd
Participating Swap US $60.00 per bbl (max to 59 percent above the floor price)
January 1 - September 30
 
 
Midstream
   
 Volume
   
Year
Product
(Buy)
Sell
Terms
Effective Period
2007
Crude Oil
250
Bpd
Costless Collar US $64.50 floor, US $69.20 ceiling
January 1 - December 31
 
 
2,000
Bpd
Costless Collar US $72.43 floor, US $80.29 ceiling
April 1 - December 31
 
 
10,077
Bpd
Cdn $77.02 per bbl
January 1 - December 31
 
 
(7,643)
Bpd
US $64.35 per bbl (4)
January 1 - March 31
 
 
(1,122)
Bpd
Cdn $80.81 per bbl (4)
January 1 - March 31
 
Natural Gas
3,000
Gjpd
Cdn $8.28 per gj
January 1 - January 31
 
 
(1,350)
Gjpd
Costless Collar Cdn $8.62 floor, Cdn $9.10 ceiling
January 1 - December 31
 
 
(3,201)
Gjpd
Cdn $7.70 per gj
January 1 - March 31
 
 
(22,196)
Gjpd
Cdn $8.17 per gj
April 1 - December 31
 
 
(48,493)
Gjpd
Cdn $8.20 per gj
January 1 - December 31
 
Propane
9,328
Bpd
US $0.9841 per gallon (4) (6)
January 1 - March 31
 
 
806
Bpd
US $0.965 per gallon (6) (8)
January 1 - February 28
 
 
1,666
Bpd
US $0.9668 per gallon (6) (8)
January 1 - March 31
 
 
948
Bpd
Cdn $1.2081 per gallon (4) (6)
January 1 - March 31
 
Normal Butane
1,808
Bpd
US $1.1135 per gallon (4) (7)
January 1 - March 31
 
 
306
Bpd
Cdn $1.3788 per gallon (4) (7)
January 1 - March 31
 
Foreign Exchange
 
 
Sell US $817,163 per month @ 1.1434 (5)
January 1 - December 31
 
 
 
 
Sell US $968,486 per month @ 1.1013 (5)
April 1 - December 31
 
 
 
 
 
 
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 $73.00 floor, US $80.00 ceiling
January 1 - June 30
 
 
500
Bpd
Costless Collar US $64.00 floor, US $74.50 ceiling
January 1 - September 30
 
 
250
Bpd
US $65.60 per bbl
January 1 - December 31
 
 
8,521
Bpd
Cdn $76.65 per bbl
January 1 - December 31
 
Natural Gas
(56,824)
Gjpd
Cdn $8.34 per gj
January 1 - December 31
 
 
(13,123)
Gjpd
Cdn $8.60 per gj
January 1 - June 30
 
 
(2,965)
Gjpd
Cdn $7.94 per gj
January 1 - September 30
 
 
(8,760)
Gjpd
Cdn $7.94 per gj
July 1 - December 31
 
Foreign Exchange
 
 
Sell US $599,652 per month @ 1.1172 (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
 
- 27 -
 
2009
Crude Oil
2,500
Bpd
Costless Collar US $65.00 floor, US $69.23 ceiling
January 1 - December 31
 
 
500
Bpd
Costless Collar US $70.00 floor, US $79.00 ceiling
January 1 - June 30
 
 
1,500
Bpd
Cdn $81.44 per bbl
January 1 - June 30
 
 
250
Bpd
Cdn $77.37 per bbl
January 1 - March 31
 
 
500
Bpd
Cdn $75.10 per bbl
July 1 - December 31
 
 
250
Bpd
Cdn $76.70 per bbl
July 1 - September 30
 
 
250
Bpd
US $64.60 per bbl
January 1 - December 31
 
 
3,374
Bpd
Cdn $74.26 per bbl
January 1 - December 31
 
Natural Gas
(35,261)
Gjpd
Cdn $8.28 per gj
January 1 - December 31
 
 
(1,481)
Gjpd
Cdn $8.74 per gj
January 1 - March 31
 
 
(14,714)
Gjpd
Cdn $8.32 per gj
January 1 - June 30
 
 
(1,481)
Gjpd
Cdn $7.59 per gj
July 1 - September 30
 
 
(2,776)
Gjpd
Cdn $7.75 per gj
July 1 - December 31
 
Foreign Exchange
 
 
Sell US $522,154 per month @ 1.1093 (5)
January 1 - December 31
 
 
 
 
Sell US $1,055,833 per month @ 1.099 (5)
January 1 - June 30
 
 
 
 
 
 
2010
Crude Oil
1,500
Bpd
Costless Collar US $62.90 floor, US $67.48 ceiling
January 1 - December 31
 
 
4,688
Bpd
Cdn $72.98 per bbl
January 1 - December 31
 
Natural Gas
(35,273)
Gjpd
Cdn $8.03 per gj
January 1 - December 31
 
 
(1,485)
Gjpd
Cdn $7.09 per gj
April 1 - December 31
 
Foreign Exchange
 
 
Sell US $472,828 per month @ 1.1078 (5)
January 1 - December 31
 
 
 
 
 
 
2011
Crude Oil
500
Bpd
Costless Collar US $65.00 floor, US $75.00 ceiling
January 1 - June 30
 
 
250
Bpd
Costless Collar US $60.00 floor, US $68.10 ceiling
July 1 - September 30
 
 
250
Bpd
Costless Collar US $60.00 floor, US $67.30 ceiling
July 1 - September 30
 
 
500
Bpd
Costless Collar US $56.00 floor, US $75.25 ceiling
July 1 - September 30
 
 
500
Bpd
Costless Collar US $58.00 floor, US $76.20 ceiling
July 1 - September 30
 
 
500
Bpd
Costless Collar US $60.00 floor, US $71.60 ceiling
July 1 - September 30
 
 
3,250
Bpd
Cdn $74.26 per bbl
January 1 - June 30
 
 
750
Bpd
Cdn $69.94 per bbl
January 1 - March 31
 
 
885
Bpd
Cdn $70.99 per bbl
January 1 - September 30
 
 
250
Bpd
Cdn $73.35 per bbl
January 1 - October 31
 
 
250
Bpd
Cdn $72.75 per bbl
January 1 - November 30
 
 
500
Bpd
Cdn $73.15 per bbl
April 1 - June 30
 
Natural Gas
(2,700)
Gjpd
Cdn $8.53 per gj
January 1 - March 31
 
 
(23,726)
Gjpd
Cdn $7.46 per gj
January 1 - June 30
 
 
(4,955)
Gjpd
Cdn $7.02 per gj
January 1 - September 30
 
 
(1,481)
Gjpd
Cdn $7.25 per gj
January 1 - October 31
 
 
(1,481)
Gjpd
Cdn $7.24 per gj
January 1 - November 30
 
 
(11,859)
Gjpd
Cdn $6.72 per gj
July 1 - September 30
 
 
(2,820)
Gjpd
Cdn $6.21 per gj
April 1 - June 30
 
Foreign Exchange
 
 
Sell US $980,417 per month @ 1.0805 (5)
January 1 - June 30
 
 
 
 
Sell US $717,600 per month @ 1.0931 (5)
July 1 - September 30
 
(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 hedges to propane
(5) U.S. Dollar hedge contracts settled against Bank of Canada noon rate average
(6) Propane contracts are settled against Belvieu C3 TET
(7) Normal butane contracts are settled against Belvieu NC4 NON-TET
(8) Midstream inventory hedges 

              Credit Risk
 
Provident's Credit Policy governs the activities undertaken to mitigate the risks associated with counterparty (customer) nonpayment. The policy sets predetermined credit limits, volumes and terms for each counterparty Provident sells to. In addition, the policy sets criteria to ensure that Provident has a diversified base of creditors. Using this policy, as well as Provident's historical credit relationships with its customers, Provident manages its credit exposure.
 
Insurance
 
Provident purchases property insurance, business interruption insurance, liability/pollution insurance and well control insurance to manage the risks associated with the possibility of poor asset performance. Provident also purchases directors & officers insurance.
 
Like other businesses, Provident is subject to government regulations in the jurisdictions in which it operates. Provident participates in a range of industry and lobby groups including the Canadian Association of Petroleum Producers, the Canadian Association of Income Funds, the Coalition of Canadian Energy Trusts, the Canadian Energy Infrastructure Group and the Independent Petroleum Association of America.
 
 
Provident's Canadian reserves were evaluated by McDaniel and AJM effective December 31, 2006, in accordance with NI 51-101. Provident's U.S. reserves were evaluated by NSAI effective December 31, 2006 in accordance with NI 51-101. McDaniel, AJM and NSAI are independent qualified reserves evaluators appointed pursuant to NI 51-101. The McDaniel evaluation report is dated January 22, 2007 with a preparation date of December 31, 2006. The AJM evaluation report is dated January 24, 2007 with a preparation date of December 31, 2006 and the NSAI evaluation report is dated February 26, 2007 with a preparation date of December 31, 2006.
 
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 and NSAI dated January 22, 2007, January 24, 2007 and February 26, 2007, respectively and the Report of Management and Directors on Oil and Gas Disclosure on Form 51-101F3 dated March 7, 2007 have been filed on SEDAR at www.sedar.com and are incorporated by reference in this Renewal Annual Information Form.
 
 
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.
 
 
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 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.
 
 
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 800 rail cars.
 
 
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.
 
 
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.
 
 
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.
 
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 NGL acquisition
 
The $773.0 million Midstream NGL Acquisition, which closed on December 13, 2005, included NGL extraction plants, pipelines, storage and fractionation facilities, distribution facilities, and contracts including marketing, supply and transportation arrangements, and NGL marketing infrastructure. This acquisition extended Provident's involvement in the NGL value chain. Results in 2005 included NGL fee for service, fixed margin extraction, equity margin on marketed NGLs, and margin on crude oil marketing contracts. The crude oil marketing contracts were disposed in May 2005, thus 2006 results include an increase in fees for services, fixed margin extraction and equity margin on marketed NGLs.
 
      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:
 
 
a)
Empress East
 
b)
Redwater West
 
c)
Commercial Services
 
a) 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.
 
The income for this business line is primarily driven by the pricing relationship of natural gas at AECO to NGL values in Belvieu. 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.
 
b) 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.
 
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 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.
 
c) 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.
 
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.
 
 
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
 
Period
  
High ($)
  
Low ($)
  
Volume (000's)
2006
            
January
  
13.70
  
11.79
  
8,039
February
  
13.08
  
11.89
  
6,283
March
  
13.40
  
12.10
  
8,791
April
  
13.72
  
12.87
  
5,177
May
  
14.31
  
12.95
  
13,543
June
  
14.24
  
12.93
  
10,485
July
  
14.40
  
13.25
  
11,357
August
  
14.50
  
13.79
  
19,462
September
  
14.39
  
12.07
  
12,179
October
  
13.85
  
11.62
  
11,455
November
  
12.88
  
10.05
  
15,529
December
  
13.23
  
12.34
  
8,098
       
 
  
 
8.75 Percent Debentures
 
Period
  
High ($)
  
Low ($)
  
Volume
2006
            
January
  
120.99
  
110.67
  
3,390
February
  
113.62
  
112.00
  
1,070
March
  
123.00
  
110.27
  
1,940
April
  
123.19
  
118.56
  
5,680
May
  
126.94
  
119.11
  
12,620
June
  
130.00
  
118.20
  
4,350
July
  
129.99
  
123.34
  
8,980
August
  
130.25
  
125.50
  
3,360
September
  
130.65
  
110.27
  
4,630
October
  
123.00
  
107.27
  
6,460
November
  
113.27
  
105.00
  
4,170
December
  
116.67
  
110.95
  
2,590
 
 
8 Percent Debentures
 
Period
  
High ($)
  
Low ($)
  
Volume
2006
            
January
  
116.00
  
107.00
  
36,930
February
  
111.20
  
108.02
  
3,030
March
  
112.67
  
108.02
  
1,665
April
  
113.99
  
110.84
  
4,740
May
  
119.00
  
109.50
  
45,260
June
  
118.80
  
109.49
  
73,440
July
  
119.59
  
113.50
  
7,530
August
  
120.04
  
115.27
  
49,690
September
  
120.25
  
105.02
  
141,870
October
115.00
105.02
28,080
November
108.02
102.02
107,520
December
109.87
106.95
6,550
 
Initial 6.5 Percent Debentures
 
Period
  
High ($)
  
Low ($)
  
Volume
2006
            
January
  
104.75
  
100.30
  
59,430
February
  
104.98
  
102.00
  
15,530
March
  
104.98
  
101.78
  
13,540
April
  
105.56
  
103.26
  
15,410
May
  
106.00
  
103.06
  
22,630
June
  
105.50
  
104.00
  
48,370
July
  
105.00
  
103.01
  
16,100
August
  
105.99
  
102.60
  
32,770
September
  
105.95
  
101.51
  
30,750
October
  
104.50
  
100.17
  
29,580
November
  
101.50
  
97.00
  
49,340
December
  
101.25
  
98.50
  
18,480
   
 
  
 
    
Supplemental 6.5 Percent Debentures 
 
Period
  
High ($)
  
Low ($)
  
Volume
2006
            
January
  
107.00
  
100.50
  
196,691
February
  
103.00
  
101.75
  
72,980
March
  
103.49
  
101.26
  
61,160
April
  
103.43
  
101.81
  
66,690
May
  
103.39
  
101.31
  
82,710
June
  
103.09
  
100.01
  
43,460
July
  
102.60
  
101.00
  
14,720
August
  
103.29
  
101.51
  
36,650
September
  
102.99
  
99.26
  
21,310
October
  
102.19
  
99.01
  
15,860
November
  
99.10
  
96.01
  
27,699
December
  
100.97
  
97.51
  
36,140
       
 
    
New York Stock Exchange
 
Trust Units
 
Period
  
High (U.S.$)
  
Low (U.S.$)
  
Volume (000's)
2006
            
January
  
11.66
  
10.24
  
14,614
February
  
11.15
  
10.42
  
10,985
March
  
11.50
  
10.52
  
10,440
April
  
11.99
  
11.16
  
9,091
May
  
12.99
  
11.51
  
10,940
June
  
12.89
  
11.77
  
9,145
July
  
12.70
  
12.02
  
14,126
August
  
13.04
  
12.28
  
7,398
September
  
11.50
  
10.82
  
11,854
October
  
12.16
  
10.31
  
9,531
November
  
11.25
  
9.00
  
19,099
December
  
11.80
  
10.59
  
6,850
           
 
 
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
  
               
2005
              
January - December
  
$
1.44
  
$
1.20
  
               
2006
              
January - December
  
$
1.44
  
$
1.26
  
               
2007
              
January
  
$
0.12
  
$
0.10
  
February
  
$
0.12
  
$
0.10
  
March
  
$
0.12
  
$
0.10
  
Total to date for 2007
  
$
0.36
  
$
0.30
  

Since its inception, the Trust has paid an aggregate of $11.31 (U.S.$8.26) 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 2005.
     
 
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
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-Sep-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
15-Dec-05
$0.12
$0.1224
$13.1321
$12.4755
15-Nov-05
$0.12
$0.1224
$12,8775
$12.2336
15-Oct-05
$0.12
$0.1224
$14.0544
$13.3517
15-Sep-05
$0.12
$0.1224
$13.7481
$13.0607
13-Aug-05
$0.12
$0.1224
$13.9564
$13.2586
15-Jul-05
$0.12
$0.1224
$13.0940
$12.4393
15-Jun-05
$0.12
$0.1224
$12.5551
$11.9273
14-May-05
$0.12
$0.1224
$12.3348
$11.7181
15-Apr-05
$0.12
$0.1224
$11.9423
$11.3452
15-Mar-05
$0.12
$0.1224
$12.3099
$11.6944
13-Feb-05
$0.12
$0.1224
$11.9741
$11.3754
15-Jan-05
$0.12
$0.1224
$11.4208
$10.8498
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 800, 112 - 4th Avenue S.W., Calgary, Alberta T2P 0H3.
 
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 9, 2007.
 
Name and Background
  
Number of Trust Units
Beneficially Owned
or Controlled
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.
  
30,336
     
G.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. Prior thereto he was President and Chief Executive Officer of Norcen Energy Ltd. an oil and gas exploration and production company, from 1994 to 1998. He is also a director of Capitol Energy Resources Ltd. and BreitBurn Energy Partners LP.
  
63,364(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. and Hawk Energy Corp., Athabasca Oilsands Corp. and BreitBurn Energy Partners LP.
  
893,836(4)
     
Randall J. Findlay(3) of DeWinton, 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. Prior thereto Senior Vice President of TransCanada Pipelines Ltd., a pipeline company, and President and Chief Executive Officer of TransCanada Gas Processing L.P., a gas processing partnership, from June 1998 to August 1999. He is also a director of Canadian Helicopters Income Fund, Pembina Pipelines Income Fund, Superior Plus Inc., TransAlta Power LP. and BreitBurn Energy Partners LP.
  
767,378
     
Mr. Hugh A. Fergusson(1)(3) of Calgary, Alberta is the former Vice President and Director with Dow Chemical Canada Inc. He has been a director of Provident since 2005 and is also a director of Canexus Income Fund and Taylor NGL Limited Partnership.
  
5,000(4)
     
Norman R. Gish(2) of Calgary, Alberta is a corporate director. Prior thereto, he was the President of Gish Consulting Inc., energy consultants and previously 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)
 
- 39 -
 
     
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 a director of Winstar Resources Ltd.
  
112,686
     
Dr. Robert Mitchell(3) of Calgary, Alberta has been an independent businessman since September 2003. From 1984 to September 2003, he was Executive Vice President of Talisman Energy Inc., a public oil and gas company. He has been a director of Provident since 2004 and is also a director of Winstar Resources Ltd.
  
6,000
     
Byron J. Seaman(3) of Calgary, Alberta is an independent businessman and private investor. He has been a director of Provident since 2001 and is also a director of Rider Resources Ltd.
  
35,068
 
M.H. (Mike) Shaikh(1) of Calgary, Alberta is the President of M.H. Shaikh Professional Corporation (Chartered Accountants). He has been a director of Provident since 2001 and is also a director of Churchill Energy Inc. and Mystique Energy Inc.
 
124,684(4)
     
Jeffrey T. Smith(2)(3) of Calgary, Alberta is an independent businessman and private investor. He has been a director of Provident since 2001 and is also a director of Compton Petroleum Ltd. and Cordero Energy Inc.
  
4,900
 
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 $500,000 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.
 
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 the last six years in investment banking and most recently was Managing Director, North American Energy with TD Securities Inc. Prior to his move into investment banking, Mr. Holm practiced securities law for 15 years, most recently as a partner with Macleod Dixon llp. Mr. Holm joined Provident in 2006.
 
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.
 
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.
 
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 oil and gas 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, 2006, the Board of Directors had three committees - the Audit Committee, the Reserves, Operations and Environmental, Health and Safety Committee and the Governance, Human Resources and Compensation Committee. In addition, the Trust has established one additional committee in 2006 - the Disclosure Committee, which is comprised entirely of members of management. Membership in each committee is set forth below.
 
Audit Committee
 
The Audit Committee consists of Mr. M.H. (Mike) Shaikh (Chairman), Mr. Bruce R. Libin and Mr. Hugh A. Fergusson. All members of the Audit Committee are independent and financially literate, as determined by applicable securities legislation, and at least one member of the Committee is an "audit committee financial expert" as required by U.S. securities laws. The Audit Committee reviews the Trust's interim unaudited consolidated financial statements and annual audited consolidated financial statements 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 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 oil and natural gas industry and, as a result of these and other activities, the directors and officers of Provident may become subject to conflicts of interest. The ABCA provides that in the event that a director has an interest in a contract or proposed contract or agreement, the director shall disclose his interest in such contract or agreement and shall refrain from voting on any matter in respect of such contract or agreement unless otherwise provided under the ABCA. To the extent that conflicts of interest arise, such conflicts will be resolved in accordance with the provisions of the ABCA.
 
As at the date hereof, Provident is not aware of any existing or potential material conflicts of interest between Provident and a director or officer of Provident.
 
 
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
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.

 
Name
Independent
Financially
Literate
Relevant Education and Experience
Hugh A. Fergusson
Yes
Yes
Mr. Fergusson holds the degrees of Bachelor of Arts and Bachelor of Laws. He has also completed Advanced Management Programs at the University of Western Ontario and Northwestern University. He is an independent businessman and Corporate Director. Mr. Fergusson practiced law for five years following which he was employed by the Dow Chemical Company (and related companies) for 27 years until he retired in 2004. During his career with Dow, Mr. Fergusson obtained significant financial experience and exposure to accounting and financial issues through a series of roles including commercial and business leadership largely related to hydrocarbons and energy. In addition to being a director of a number of Dow subsidiaries, Mr. Fergusson was Chairman of Petromont Inc. from 2002 until 2004 and a member of its Audit Committee from 2002 until 2004.
 
External Auditor Service Fees
 
The following table sets forth information about the fees billed to the Trust and its Canadian and U.S. subsidiaries for professional services provided by PricewaterhouseCoopers LLP during fiscal 2006 and 2005. PricewaterhouseCoopers LLP is independent in accordance with the auditor's rules of professional conduct in Canada.
 
(CDN$) 
  
2006
  
2005
  
Audit Fees
  
$
2,000,000
  
$
929,000
  
Audit-Related Fees
    
1,294,900
    
30,000
  
Tax Fees
    
1,226,000
    
776,300
  
All Other Fees
    
60,300
    
-
  
Total
  
$
4,581,200
  
$
1,735,300
  

Audit Fees
 
Fees for audit services totalled approximately $2.0 million in 2006 and approximately $929,000 in 2005, including fees associated with the annual audit, the reviews of the Trust's quarterly reports, statutory audits and regulatory filings. Fees in 2006 have increased as a result of a comprehensive audit that incorporates work undertaken by the auditors to assess management internal controls under Section 404 of the Sarbanes Oxley Act.
 
Audit-Related Fees
 
Fees for audit-related services totalled approximately $1.3 million in 2006 and approximately $30,000 in 2005. Audit related services include consultations concerning documents filed with respect to audits in connection with proposed or successfully transacted acquisitions and for 2006 included work related to the initial public offering by BreitBurn Energy Partners L.P.
 
Tax Fees
 
Fees for tax services totalled approximately $1.2 million in 2006 and approximately $776,300 in 2005. Fees for tax services include tax compliance, tax planning and tax advice services.
 
All Other Fees
 
Fees for all other services totalled approximately $60,300 in 2006 and nil in 2005.
 
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.
 
 
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.
 
Provincial Royalties and Incentives
 
In addition to federal regulation, each province has legislation and regulations, which govern land tenure, royalties, production rates, environmental protection and other matters. The royalty regime is a significant factor in the profitability of oil and natural gas production. Royalties payable on production from lands other than Crown lands are determined by negotiations between the mineral owner and the lessee. Crown royalties are determined by governmental regulation and are generally calculated as a percentage of the value of the gross production, and the rate of royalties payable generally depends in part on well productivity, geographical location, field discovery data and the type or quality of the petroleum product produced.
 
From time to time the governments of Canada and Alberta have established incentive programs, which have included royalty rate reductions, royalty holidays and tax credits for the purpose of encouraging oil and natural gas production and enhanced production projects.
 
Alberta
 
In Alberta, a producer of oil or natural gas is entitled to a credit against the royalties payable to the Crown by virtue of the ARTC program. The ARTC rate is based on a price-sensitive formula and varies between 75 percent for prices at or below the royalty tax credit reference price of $100 per m3 decreasing to 25 percent for prices above the royalty tax credit reference price of $210 per m3. The ARTC rate will be applied to a maximum annual amount of $2.0 million of Alberta Crown royalties payable for each producer or associated group of producers. Crown royalties on production from producing properties acquired from corporations claiming maximum entitlements to ARTC will generally not be eligible for ARTC. The rate is established quarterly based on the average par price, as determined by the Alberta Department of Energy.
 
On October 13, 1992, the Alberta government announced major changes to its royalty structure and permanent incentives for exploring and developing oil and gas reserves. The significant changes announced which remain in force include the following: (i) the first wells drilled in new oil pools discovered on or after October 1, 1992 will have a permanent one year oil royalty holiday, subject to a $1.0 million cap and a reduced royalty rate thereafter; (ii) reduction of royalties on pre-October 1, 1992 production of oil and gas; (iii) incentives by way of royalty holidays and reduced royalties on reactivated, low productivity and horizontal re-entry of vertical oil wells; (iv) introduction of separate par pricing for light, medium and heavy oil; and (v) modification of the royalty formula structure to provide for sensitivity to price fluctuations.
 
Environmental Regulation
 
The oil and natural gas industry is currently subject to environmental regulations pursuant to provincial and federal legislation. Environmental legislation provides for restrictions and prohibitions on releases or emissions of various substances produced in association with certain oil and gas industry operations. In addition, legislation requires that well and facility sites be abandoned and reclaimed to the satisfaction of provincial authorities. A breach of such legislation may result in the imposition of fines and penalties, the suspension or revocation of necessary licenses and civil liability. Environmental legislation in Alberta has been consolidated into the Environmental Protection and Enhancement Act (Alberta), which took effect on September 1, 1993. The Environmental Protection and Enhancement Act (Alberta) imposes stricter environmental standards, requires more stringent compliance and reporting and significantly increases penalties for non-compliance.
 
Exports from Canada
 
In order to export oil or natural gas from Canada, certain approvals are required from the National Energy Board and the Government of Canada. The approval(s) required are dependent on the hydrocarbon substance being exported and the length of the proposed export arrangement.
 
 
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:
 
 
Exploitation and Development
 
Exploitation and development risks are due to the uncertain results of searching for and producing oil and natural gas using imperfect scientific methods. These risks are mitigated by using experienced staff, focusing exploitation efforts in areas in which Provident has existing knowledge and expertise or access to such expertise, using up-to-date technology to enhance methods and controlling costs to maximize returns. Advanced oil and natural gas related technologies such as three dimensional seismography, reservoir simulation studies and horizontal drilling have been used by Provident and will be used by Provident to improve its ability to find, develop and produce oil and natural gas.

              Operations
 
Provident's operations will be subject to all of the risks normally incident to the operation and development of oil and natural gas properties and the drilling of oil and natural gas wells, including encountering unexpected formations or pressures, blowouts, craterings and fires, all of which could result in personal injuries, loss of life and damage to property of Provident and others. Provident will have both safety and environmental policies in place to protect its operators and employees, as well as to meet the regulatory requirements in those areas where it operates. In addition, Provident will have liability insurance policies in place, in such amounts as it considers adequate, however, it will not be fully insured against all of these risks, nor are all such risks insurable.
 
Continuing production from a property, and to some extent the marketing of production therefrom, are largely dependent upon the ability of the operator of the property. To the extent the operator fails to perform these functions properly, revenue may be reduced. Payments from production generally flow through the operator and there is a risk of delay and additional expense in receiving such revenues if the operator becomes insolvent. Although satisfactory title reviews are generally conducted in accordance with industry standards, such reviews do not guarantee or certify that a defect in the chain of title may not arise to defeat the claim of Provident to certain of its oil and gas properties. A reduction of the income from the Provident Royalties could result in such circumstances.
 
Oil and Natural Gas Prices
 
The price of oil and natural gas will fluctuate throughout the life of Provident and price and demand are factors largely beyond its control. Such fluctuations will have a positive or negative effect on the revenue to be received by it. Such fluctuations will also have an effect on the acquisition costs of any future oil and natural gas properties that Provident may acquire. As well, cash distributions from the Trust will be highly sensitive to the prevailing price of crude oil and natural gas.
 
Marketing
 
The marketability and price of oil and natural gas, which may be acquired or discovered by Provident, will be affected by numerous factors beyond its control. These factors include demand for oil and natural gas, market fluctuations, the proximity and capacity of oil and natural gas pipelines and processing equipment and government regulations, including regulations relating to environmental protection, royalties, allowable production, pricing, importing and exporting of oil and natural gas.
 
Capital Investment
 
The timing and amount of capital expenditures will directly affect the amount of income for distribution to Trust Unitholders. Distributions may be reduced, or even eliminated, at times when significant capital or other expenditures are made.
 
Debt Service
 
Provident currently has term credit facilities of $925.0 million and U.S.$158.0 million. Variations in interest rates and scheduled principal repayments could result in significant changes in the amount required to be applied to debt service before payment of any amounts to the Trust. Although it is believed that the bank line of credit is sufficient, there can be no assurance that the amount will be adequate for the financial obligations of Provident or that additional funds can be obtained.
 
The 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 lender may foreclose on or sell Provident's oil and gas properties free from or together with the Provident Royalties.
 
Reserves
 
Although McDaniel, AJM, NSAI and Provident have carefully prepared the reserve figures included herein such figures are estimates and no assurance can be given that the indicated levels of reserves will be produced. Probable reserves estimated for properties may require revision based on the actual development strategies employed to prove such reserves. Declines in the reserves of Provident, which are not offset by the acquisition, or development of additional reserves may reduce the underlying value of Trust Units to Trust Unitholders. The value of the Trust Units attributable to the oil and gas reserves will have no value once all of the oil and natural gas reserves of Provident have been produced. As a result, holders of Trust Units will have to obtain the return of capital invested out of cash flow derived from their investment in such Trust Units.
 
Environmental Concerns
 
The oil and natural gas industry is subject to environmental regulation pursuant to local, provincial and federal legislation. A breach of such legislation may result in the imposition of fines or issuance of clean up orders in respect of Provident or its oil and gas properties. Such legislation may be changed to impose higher standards and potentially more costly obligations on Provident. Although Provident has established a reclamation fund for the purpose of funding its currently estimated future environmental and reclamation obligations based on its current knowledge, there can be no assurance that the Trust will be able to satisfy its actual future environmental and reclamation obligations.
 
Delay in Cash Distributions
 
In addition to the usual delays in payment by purchasers of oil and natural gas to the operators of oil and gas properties, and by the operator to Provident, payments between any of such parties may also be delayed by restrictions imposed by lenders, delays in the sale or delivery of products, delays in the connection of wells to a gathering system, blowouts or other accidents, recovery by the operator of expenses incurred in the operation of oil and gas properties or the establishment by the operator of reserves for such expenses.
 
Reliance on Provident
 
Unitholders will be dependent on the management of Provident in respect of the administration and management of all matters relating to Provident's oil and gas properties, the royalties, the Trust and Trust Units. Investors who are not willing to rely on the management of Provident should not invest in the Trust Units.
 
Depletion of Reserves
 
The Trust has certain unique attributes, which differentiate it from other oil and gas industry participants. Distributions of Distributable Cash in respect of Provident's oil and gas properties, absent commodity price increases or cost effective acquisition and development activities, will decline over time in a manner consistent with declining production from typical oil, natural gas and natural gas liquids reserves. Provident will not be reinvesting cash flow in the same manner as other industry participants. Accordingly, absent capital injections, Provident's initial production levels and reserves will decline.
 
Provident's future oil and natural gas reserves and production, and therefore its cash flows, will be highly dependent on Provident's success in exploiting its reserve base and acquiring additional reserves.  Without reserve additions through acquisition or development activities, Provident's reserves and production will decline over time as reserves are exploited. 
 
To the extent that external sources of capital, including the issuance of additional Trust Units (through public offerings, the DRIP or otherwise) become limited or unavailable, Provident's ability to make the necessary capital investments to maintain or expand its oil and natural gas reserves will be impaired. To the extent that Provident is required to use cash flow to finance capital expenditures or property acquisitions, the level of Distributable Cash will be reduced.
 
There can be no assurance that Provident will be successful in developing or acquiring additional reserves on terms that meet the Trust's investment objectives. 
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.
 
The rate and timing of production from proven natural gas reserves tied into the gas plants is at the discretion of the producers and is subject to regulatory constraints. The producers have no obligation to produce natural gas from these lands.
 
Provident's natural gas midstream, NGL processing and marketing business is connected to various third party trunkline systems. Operational disruptions or apportionment on those third party systems may prevent the full utilization of the business.
 
Over the long term, business will depend, in part, on the level of demand for NGLs and natural gas in the geographic areas in which deliveries are made by pipelines and the ability and willingness of shippers having access or rights to utilize the pipelines to supply such demand. Provident cannot predict the impact of future economic conditions, fuel conservation measures, alternative fuel requirements, governmental regulation or technological advances in fuel economy and energy generation devices, all of which could reduce the demand for natural gas and NGLs.
 
Bank Financing
 
Variations in interest rates and scheduled principal repayments could result in significant changes in the amount required to be applied to debt service before payment of any amounts to the Trust. Although it is believed that this credit facility is sufficient, there can be no assurance that the amount will be adequate for the financial obligations of Provident or that additional funds can be obtained.
 
The lenders have been provided with security over substantially all of the assets of Provident. If Provident becomes unable to pay its debt service charges or otherwise commits an event of default such as bankruptcy, the lenders may foreclose on or sell Provident's oil and gas properties and other assets.
 
Operational Matters and Hazards
 
Provident's operations will be subject to common hazards of the natural gas processing and pipeline transportation business. The operation of Provident's natural gas midstream, NGL processing and marketing business could be disrupted by natural disasters or other events beyond the control of Provident. A casualty occurrence could result in the loss of equipment or life, as well as injury and property damage. Provident carries insurance coverage with respect to some, but not all, casualty occurrences in amounts customary for similar business operations, which coverage may not be sufficient to compensate for all casualty occurrences.
 
The operation of Provident's natural gas midstream, NGL processing and marketing business will involve many risks, including the breakdown or failure of equipment, information systems or processes, the performance of equipment at levels below those originally intended (whether due to misuse, unexpected degradation or design, construction or manufacturing defects), failure to maintain an adequate inventory of supplies or spare parts, operator error, labour disputes, disputes with owners of interconnected facilities and carriers and catastrophic events such as natural disasters, fires, explosions, fractures, acts of eco-terrorists and saboteurs, and other similar events, many of which are beyond the control of the Trust or Provident. The occurrence or continuance of any of these events could increase the cost of operating facilities and/or reduce its processing or throughput capacity, thereby reducing cash flow.
 
Operating and Capital Costs
 
Operating and capital costs of Provident's natural gas midstream, NGL processing and marketing business may vary considerably from current and forecast values and rates and represent significant components of the cost of providing service. In general, as equipment ages, maintenance capital expenditures and maintenance expenses with respect to such equipment may increase over time. Distributions may be reduced if significant increases in operating or capital costs are incurred.
 
Although operating costs are to be recaptured through the tariffs charged on natural gas volumes processed and oil and NGLs transported, respectively, to the extent such charges escalate, producers may seek lower cost alternatives or stop production of their natural gas.
 
Competition
 
Provident's natural gas midstream, NGL processing and marketing business is subject to competition from other gas processing plants which are either in the general vicinity of the gas plants or have gathering systems that are or could potentially extend into areas served by the gas plants. The pipelines and storage, terminal and processing facilities are also subject to competition from other pipelines and storage, terminal and processing facilities in the areas they serve, and the gas products marketing business is subject to competition from other marketing firms.
 
Producers in Alberta compete with producers in other regions to supply natural gas and gas products to customers in North America and the natural gas and gas products industry also competes with other industries to supply the fuel, feedstock and other needs of consumers. Such competition may have an adverse effect on the production of natural gas and gas products in Alberta and, as a result, on the demand for Provident's services.
 
Regulatory Intervention
 
Pipelines and facilities can be subject to common carrier and common processor applications and to rate setting by regulatory authorities in the event agreement on fees or tariffs cannot be reached with producers. To the extent that producers believe processing fees or tariffs respecting pipelines and facilities are too high, they may seek rate relief through regulatory means.
 
Environmental Considerations
 
Major equipment failure, release of toxic substances or pipeline rupture could result in damage to the environment and Provident's natural gas midstream, NGL processing and marketing business, death or injury and substantial costs and liabilities to third parties. Provident may not be able to insure against these events or may elect not to insure because of high premium costs or for other reasons. If, at any time, appropriate regulatory authorities deem any one of the gas plants unsafe, they may order it to be shut down.
 
The gas processing and gathering industry is regulated by federal and provincial environmental legislation. Activities that do not meet regulatory standards or that breach such legislation may result in the imposition of fines, penalties and suspension of operations. It is possible that increasingly strict environmental and safety laws will be implemented, which could result in substantial costs of compliance.
 
      Abandonment
 
Provident will be responsible for compliance with all laws and regulations regarding abandonment of Provident's natural gas midstream, NGL processing and marketing business at the end of their economic life, which abandonment costs may be substantial. It is not possible to estimate the abandonment costs at this time as they will be a function of regulatory requirements at the time of abandonment.
 
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 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.
 
 
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.
 
The retention of "mutual fund trust" status under the Tax Act is important for both resident and non-resident holders of Trust Units and not just for holders of Trust units held within Canadian tax exempt plans. The loss of such status could be expected to have a significant adverse effect on the market price of the Trust Units. The importance of mutual fund status and the consequences of losing such status are set forth below:
 
(a)
By virtue of its status as a mutual fund trust, the Trust has been accepted for registration effective March 6, 2001 as a "registered investment" for registered retirement savings plans ("RRSPs"), registered retirement income funds ("RRIFs"), and deferred profit sharing plans ("DPSPs") (collectively, "Exempt Plans"). As such, Trust Units are qualified investments for Exempt Plans as well as registered education savings plans ("RESPs") and if the Trust's status as a "registered investment" is revoked in any year by virtue of ceasing to be a "mutual fund trust" the Trust Units would remain as qualified investments for Exempt Plans and RESPs until the end of the year following such year;
 
(b)
Where at the end of any month an Exempt Plan or a RESP holds Trust Units that are not qualified investments, the Exempt Plan or RESP must, in respect of that month, pay a tax under Part XI.1 of the Tax Act equal to 1 percent of the fair market value of the Trust Units at the time such Trust Units were acquired by the Exempt Plan or RESP. An RRSP or RRIF holding Trust Units that are not qualified investments would become taxable on income attributable to the Trust Units while they are not qualified investments (including the entire amount of any capital gain arising on a disposition of the non-qualified investment). RESPs which hold Trust Units that are not qualified investments may have their registration revoked by the Canada Revenue Agency;
 
(c)
The loss of mutual fund trust status would render the Trust liable for the payment of a tax under Part XII.2 of the Tax Act in respect of certain designated income. The payment of Part XII.2 tax by the Trust could have adverse consequences to Unitholders who are not residents of Canada and to certain Unitholders which are tax exempt entities since the amount of cash available for cash distributions would be reduced by the amount of such tax;
 
(d)
The loss of mutual fund trust status would result in the Trust ceasing to be eligible for the capital gains refund mechanism available under the Tax Act; and
 
(e)
Upon the loss of mutual fund trust status, the Trust Units held by Unitholders that are not residents of Canada would become taxable Canadian property. Such Unitholders would be subject to Canadian income tax on any gains realized on a disposition of Trust Units, and to reporting requirements in respect thereof.
 
For the purpose of maintaining the Trust's status as a "mutual fund trust" under the Tax Act, Provident may, in accordance with the Trust Indenture:
 
(a)
require the Trustee to refuse to accept a subscription for Trust Units from, or issue or register a transfer of Trust Units to a person unless the person provides a declaration that the Trust Units to be issued or transferred to such person will (when issued or transferred) not be beneficially owned by a non-resident;

 
(b)
to the extent practicable in the circumstances, send a notice to registered holders of Trust Units which are beneficially owned by non-residents, chosen in inverse order to the order of acquisition or registration of such Trust Units beneficially owned by non-residents or in such other manner as Provident may consider equitable and practicable, requiring them to sell their Trust Units which are beneficially owned by non-residents or a specified portion thereof within a specified period of not less than 60 days. If the Unitholders receiving such notice have not sold the specified number of such Trust Units or provided Provident with satisfactory evidence that such Trust Units are not beneficially owned by non-residents within such period, Provident may, on behalf of such registered Unitholder, sell such Trust Units and, in the interim, suspend the voting and distribution rights attached to such Trust Units and make any distribution in respect of such Trust Units by depositing such amount in a separate bank account in a Canadian chartered bank (net of any applicable taxes). Upon such sale, the affected holders shall cease to be holders of Trust Units so disposed of and their rights shall be limited to receiving the net proceeds of sale, and any distribution in respect thereof deposited as aforesaid, net of applicable taxes and costs of sale, upon surrender of the certificates representing such Trust Units;
 
(c)
delist the Trust Units from any non-Canadian stock exchange; and
 
(d)
take such other actions as the board of directors of Provident determines, in its sole discretion, are appropriate in the circumstances that will reduce or limit the number of Trust Units held by non-resident Unitholders to ensure that the Trust is not maintained primarily for the benefit of non-residents.
 
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. If the Trust ceases to qualify as a "mutual fund trust" under the Tax Act, there are various negative consequences as set out above under "Risks Associated With the Level of Foreign Ownership".
 
On March 27, 2007 the Minister of Finance (Canada) released a Notice of Ways and Means Motion to implement certain legislation respecting the October 31 Proposals relating to the taxation of certain distributions from certain "specified investment flow-through" ("SIFT") trusts and SIFT partnerships. The October 31 Proposals would 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 October 31 Proposals until January 1, 2011. Assuming the October 31 Proposals are enacted in their current form, the implementation of such legislation would be 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 October 31 Proposals, 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 October 31 Proposals 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 October 31 Proposals 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 October 31 Proposals 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 October 31 Proposals 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 October 31 Proposals.
 
The proposals provide 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 October 31 Proposals could be realized by the Trust sooner than January 1, 2011. On December 15, 2006, the Department of Finance (Canada) issued guidelines on the meaning of "normal growth" in this context. Specifically, the Department of Finance stated 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 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 Department of Finance's guidelines 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.
 
It is not known at this time when the October 31 Proposals will be enacted by Parliament, if at all, or whether the October 31 Proposals will be enacted in the form currently proposed.
 
Investment Eligibility
 
The Trust will endeavour to ensure that the Trust Units continue to be qualified investments for Exempt Plans and RESPs. The Tax Act imposes penalties for the acquisition or holding of non-qualified or ineligible investments and there is no assurance that the conditions prescribed for such qualified or eligible investments will be adhered to at any particular time.
 
Nature of Trust Units
 
The Trust Units do not represent a traditional investment in the oil and natural gas sector and should not be viewed by investors as shares in Provident. The Trust Units represent a fractional interest in the Trust.

The Trust Units will not represent a direct investment in Provident's business. As holders of Trust Units, Trust Unitholders will not have the statutory rights normally associated with ownership of shares of a corporation including, for example, the right to bring "oppression" or "derivative" actions.
 
The price per Trust Unit is a function of the anticipated Distributable Cash, the oil and gas properties of Provident and Provident's ability to affect long-term growth in the value of the Trust. The market price of the Trust Units will be sensitive to a variety of market conditions including, but not limited to, interest rates and the ability of the Trust to acquire suitable oil and natural gas properties. Changes in market conditions may adversely affect the trading price of the Trust Units.
 
The Trust Units are not "deposits" within the meaning of the Canada Deposit Insurance Corporation Act (Canada) and are not insured under the provisions of that Act or any other legislation. Furthermore the Trust is not a trust company and, accordingly, it is not registered under any trust and loan company legislation as it does not carry on or intend to carry on the business of a trust company.
 
Redemption Right
 
It is anticipated that the redemption right will not be the primary mechanism for Trust Unitholders to liquidate their investments. Notes which may be distributed in specie to Trust Unitholders in connection with a redemption, will not be listed on any stock exchange and no established market is expected to develop for such notes. Cash redemptions are subject to limitations.
 
Unitholder Limited Liability
 
The Trust Indenture provides that no Trust Unitholder will be subject to any liability in connection with the Trust or its assets or obligations and, in the event that a court determines that Trust Unitholders are subject to any such liabilities, the liabilities will be enforceable only against, and will be satisfied only out of, the Unitholder's share of the Trust's assets.
 
The Trust Indenture provides that all written instruments signed by or on behalf of the Trust must contain a provision to the effect that such obligation will not be binding upon Unitholders personally. Personal liability may also arise in respect of claims against the Trust that do not arise under contracts, including claims in tort, claims for taxes and possibly certain other statutory liabilities. The possibility of any personal liability of this nature arising is considered unlikely.
 
The operations of the Trust will be conducted, upon the advice of counsel, in such a way and in such jurisdictions as to avoid as far as possible any material risk of liability on the Trust Unitholders for claims against the Trust.
 
On July 1, 2004 the Income Trusts Liability Act (Alberta) came into force. This Act creates a statutory limitation on the liability of unitholders of Alberta income trusts such as the Trust. The legislation provides that a unitholder will not be, as a beneficiary, liable for any act, default, obligation or liability of the trustee that arises after the legislation come into effect.
 
Regulatory Matters
 
Provident's operations are subject to a variety of federal, provincial laws and regulations, including laws and regulations relating to the protection of the environment.
 
Conflicts of Interest
 
The directors and officers of Provident are engaged in and will continue to engage in other activities in the oil and natural gas industry and, as a result of these and other activities, the directors and officers of Provident may become subject to conflicts of interest. The ABCA provides that in the event that a director has an interest in a contract or proposed contract or agreement, the director shall disclose his interest in such contract or agreement and shall refrain from voting on any matter in respect of such contract or agreement unless otherwise provided under the ABCA. To the extent that conflicts of interest arise, such conflicts will be resolved in accordance with the provisions of the ABCA. The business of Provident is subject to other risks and matters, which are outside of their control.
 
Competition
 
The industry is highly competitive in the acquisition of exploration prospects and the development of new sources of production and the sale of oil and natural gas.
 
Dependence on Key Personnel
 
The success of the operations of Provident will be largely dependent on the skills and expertise of key personnel to manage the overall business and, in the natural gas midstream, NGL processing and marketing business, to achieve positive margins. The continued success of Provident will be dependent on its ability to retain or recruit such personnel.
 
Variations in Interest Rates and Foreign Exchange Rates
 
Variations in interest rates could result in a significant change in the amount Provident pays to service debt, potentially impacting distributions to Unitholders.
 
In addition, the exchange rate for the Canadian dollar versus the U.S. dollar has increased significantly over the last 12 months, resulting in the receipt by the Trust of fewer Canadian dollars for its production which may affect future distributions. Provident has initiated certain hedges to mitigate these risks. The increase in the exchange rate for the Canadian dollar and future Canadian/United States exchange rates may impact future distributions and the future value of the Trust's reserves as determined by independent evaluators.
 
Statutory Remedies
 
The Trust is not a legally recognized entity within the relevant definitions of the Bankruptcy and Insolvency Act (Canada), the Companies' Creditors Arrangement Act (Canada) and in some cases, the Winding Up and Restructuring Act (Canada). As a result, in the event a restructuring of the Trust were necessary, the Trust would not be able to access the remedies available thereunder. In the event of a restructuring, a holder of Debentures may be in a different position than a holder of unsecured indebtedness of a corporation.
 
Availability of Credit
 
As of March 15, 2007, the Trust had drawn $638.0 million against the Canadian credit facility and had $28.0 million of the Canadian credit facility drawn on letters of credit, representing 72 percent of the Canadian credit capacity. In addition, as of March 15, 2007, the Trust had drawn US$58.0 million against the U.S. credit facility and had US$4.0 million of the U.S. credit facility drawn on letters of credit, representing 39 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. 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.
 
 
No director or executive officer of Provident, no person or company that is the direct or indirect beneficial owner of, or who exercises control or direction over more than 10 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 will materially affect the Trust, other than as described in this Annual Information Form.
 
 
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.
 
 
As of the date hereof, the principals of McDaniel, independent oil and gas reservoir engineers, as a group, beneficially own, directly or indirectly, less than 1 percent of the Trust Units. As of the date hereof, the principals of NSA, independent oil and gas reservoir engineers, as a group, do not beneficially own, directly or indirectly, any Trust Units. As of the date hereof, the principals of 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 principals of GLJ, independent oil and gas reservoir engineers, as a group, beneficially own, directly or indirectly, less than 1 percent of the Trust Units.
 
 
Other than the Trust Indenture, there are no material contracts entered into by the Trust or its subsidiaries during the most recently completed financial year or since January 1, 2002 and which are still in effect, other than contracts entered into in the ordinary course of business.
 
Any statement contained in a document incorporated or deemed to be incorporated by reference herein shall be deemed to be modified or superseded for the purposes of this Annual Information Form to the extent that a statement contained herein, or any other subsequently filed document which also is or is deemed to be incorporated by reference herein, modifies or supersedes that statement. The modifying or superseding statement need not state that it has modified or superseded a prior statement or include any other information set forth in the document that is modified or superseded. The making of a modifying or superseding statement shall not be deemed an admission for any purposes that the modified or superseded statement, when made, constituted a misrepresentation, an untrue statement of a material fact or an omission to state a material fact that is required to be stated or that is necessary to make a statement not misleading in light of the circumstances in which it was made. Any statement so modified or superseded shall not be deemed, except as so modified or superseded, to constitute a part of this Annual Information Form.
 
The Trust will provide without charge to each security holder to whom this Annual Information Form is delivered, upon the written or oral request of such person (and to each person who is not a security holder of the Trust upon payment of a reasonable charge), a copy of any or all of the documents incorporated herein by reference, other than exhibits to such documents (unless such exhibits are specifically incorporated by reference into such documents). Requests for such documents should be directed to the office of Investor Relations, Provident Energy Ltd., 800, 112 - 4th Street S.W., Calgary, Alberta T2P 0H3, telephone: (403) 296-2233. Documents incorporated by reference in this Annual Information Form are also available on SEDAR at www.sedar.com.
 
 
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, 2007, the directors and senior officers of Provident, as a group, beneficially owned, directly or indirectly, 2,123,241 Trust Units or approximately 1 percent of the issued and outstanding Trust Units.
 
 
Additional information related to the remuneration of the directors and officers of Provident for the year ended December 31, 2006, 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 28, 2007, which relates to the Annual Meeting of the Unitholders to be held on May 9, 2007. 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, 2006.
 
Additional copies of this Annual Information Form are available on SEDAR at www.sedar.com or may be obtained from Provident. Please contact:
 
 
 
 Laurie Stretch
  
 
 Investor Relations
  
 
 Provident Energy Ltd.
  
 
 800, 112 - 4th Street S.W.
  
 
 Calgary, Alberta T2P 0H3
  
 
 
  
 
 Telephone: (403) 296-2233
  
 
 Fax:  (403) 261-6696
  
     
     
 
Additional information relating to the Trust may be found on SEDAR at www.sedar.com.
 
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.
 
Communication, Authority to Engage Advisors and Expenses
 
The Committee shall have access to such officers and employees of the Provident, the external auditor, the independent reserves evaluator(s) and to such other information respecting Provident, as it considers to be necessary or advisable in order to perform its duties and responsibilities.
 
The Committee provides an avenue for communication, particularly for outside directors, with the external auditor and financial and senior management and the Board. The external auditor shall have a direct line of communication to the Committee through its Chair and shall report directly to the Committee. The Committee, through its Chair, may directly contact any employee of Provident as it deems necessary, and any employee may bring before the Committee, on a confidential basis, any matter involving Provident's financial practices or transactions.
 
The Committee has the authority to engage independent counsel and other advisors as it determines necessary to carry out its duties and to set the compensation for any such counsel and advisors. Any engagement of independent counsel or other advisors is to be at Provident's expense.
 
Provident shall be responsible for all expenses of the Committee that are deemed necessary or appropriate by the Committee in carrying out its duties including the compensation of the external auditor for issuing an audit report or performing other audit, review or attest services.
 
Meetings and Record Keeping
 
Meetings of the Committee shall be conducted as follows:
 
1.
the Committee shall meet at least quarterly at such times and at such locations as the Chair of the Committee shall determine, provided that meetings shall be scheduled so as to permit timely review of the Trust's quarterly and annual financial statements and related management's discussion and analysis and earnings press releases. The external auditor or any two members of the Committee may also request a meeting of the Committee. The Committee shall also meet separately with the external auditor and/or internal auditor periodically as the Committee may deem appropriate. The Chair of the Committee shall hold in camera sessions of the Committee, without management present, at every meeting;
 
2.
the Chair of the Committee shall preside as chair at each Committee meeting and lead Committee discussion on meeting agenda items;
 
3.
the quorum for meetings shall be a majority of the members of the Committee, present in person or by telephone or by other telecommunication device that permits all persons participating in the meeting to hear each other;
 
4.
if the Chair of the Committee is not present at any meeting of the Committee, one of the other members of the Committee who is present at the meeting shall be chosen by the Committee to preside at the meeting;
 
5.
the Chair shall, in consultation with management and the external auditor, establish the agenda for the meetings and instruct management to ensure that properly prepared agenda materials are circulated to the Committee with sufficient time for study prior to the meeting;
 
 
6.
every question at a Committee meeting shall be decided by a majority of the votes cast;
 
7.
the Chief Executive Officer (the "CEO"), the President and the Chief Financial Officer ("CFO") shall be available to advise the Committee, shall receive notice of meetings and may attend meetings of the Committee at the invitation of the Chair of the Committee. Other management representatives, other Board members, officers or employees of Provident, the external auditor, outside counsel and other experts or consultants may be invited to attend as necessary; and
 
8.
a Committee member, or any other person selected by the Committee, shall be appointed at each meeting to act as secretary for the purpose of recording the minutes of each meeting.
 
The Committee shall provide the Board with a summary of all meetings together with a copy of the minutes from such meetings. Where minutes have not yet been prepared, the Chair shall provide the Board with oral reports on the activities of the Committee. Information reviewed and discussed by the Committee at any meeting shall be referred to in the minutes and made available for examination by the Board upon request to the Chair of the Committee.
 
Responsibilities
 
The Committee is part of the Board. Its primary functions are to assist the Board in fulfilling its oversight responsibilities with respect to: (i) the integrity of the Trust's Financial Statements, including the review and recommendation for approval of the financial statements and the financial reporting of the Trust; (ii) the assessment of the system of internal, accounting and financial reporting controls and procedures that management has established, including for the purpose of monitoring its compliance with regulatory requirements; and (iii) the appointment, compensation and evaluation of the external auditor and the oversight of the external audit process, including the external auditor's performance, qualifications and independence. In addition, the Committee shall assist the Board as requested in fulfilling its oversight responsibilities with respect to: (i) financial policies and strategies; (ii) financial risk management practices; and (iii) transactions or circumstances which could materially affect the financial profile of the Trust.
 
Management is responsible for establishing and maintaining controls, procedures and processes and the Committee is appointed by the Board to oversee, review and monitor those controls, procedures and processes.
 
The Committee, in its capacity as a committee of the Board and subject to the rights of unitholders and applicable law, shall be directly responsible for overseeing the relationship of the external auditor with the Trust, including the appointment, compensation, retention and oversight of the work of any external auditor engaged (including resolution of disagreements between management of Provident and the external auditor regarding financial reporting) for the purpose of preparing or issuing an audit report or performing other audit, review or attest services for the Trust. The external auditor shall report directly to the Committee. The Committee should have a clear understanding with the external auditor that such external auditor must maintain an open and transparent relationship with the Committee, and that the ultimate accountability of the external auditor is to the unitholders of the Trust.
 
Specific Duties
 
In carrying out its role, the Committee has the following specific authorities and responsibilities:
 
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:
 
 
 
(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;
 
 
(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;
 

 
(c)
the Committee shall, at least annually, provide a review of the Corporation's directors and officers liability insurance to the board.
 
5.
Compliance and Review of CEO and CFO Certification Process
 
 
(a)
to review Provident's financial reporting procedures and policies to ensure compliance with all legal and regulatory requirements and to investigate any non-adherence to those procedures and policies; and
 
 
(b)
in connection with its review of the annual audited financial statements and interim financial statements, the Committee will also review the process for the CEO and CFO certifications with respect to the financial statements and Provident's disclosure and internal controls, including any material deficiencies or changes in those controls. The Committee will review with the CEO, the CFO and the external auditor: (i) all significant deficiencies and material weaknesses in the design or operation of Provident's internal control over financial reporting which could adversely affect Provident's ability to record, process, summarize and report financial information required to be disclosed by the Trust in the reports that it files or submits under the United States Securities Exchange Act of 1934, as amended, within the required time periods, and (ii) any fraud, whether or not material, that involves management of Provident or other employees who have a significant role in Provident's internal control over financial reporting.
 
Other Matters
 
1.
The Committee shall review and reassess the adequacy of this mandate at least annually and otherwise as it deems appropriate and recommend changes to the Board.
 
2.
The performance of the Committee shall be evaluated annually by the Board against criteria defined in the Committee and Board mandates.
 
3.
The Committee may, at the request of the Board or on its own initiative, investigate such other matters as it considers necessary or appropriate in the circumstances, including, without limitation, matters relating to corporate governance, compensation and director nominations.
 
4.
The Committee may delegate its responsibilities to sub-committees of the Committee.
 
APPENDIX A
 
AUDIT COMMITTEE ANNUAL CALENDAR
(December 31 year end)
 
Quarterly Audit Committee Meetings: May, August and November
 
· Approval of quarterly financial statements such as:
MD&A;
press release;
estimates and management judgments; and
Review of report from external auditor. 
 
· Management certification process with report from CEO/CFO and processes followed.
 
· Other standard items including management reporting on:
Material communication with rating agencies;
Material legal matters/litigation; and
Analyst reports.
 
·
Report from Audit Committee Chair on pre-approvals for audit, non-audit, review or attestation assignments.
 
· In camera review with external auditor.
 
February or March Meeting to Review Audited Financial Statements
 
· Review annual financial statements, MD&A and related disclosure.
 
· Discuss significant accounting policies.
 
· Discuss critical estimates, and judgments and impact on statements.
 
· Review business risks disclosure in MD&A.
 
·
Receive external auditor's report on statutory audit and various matters where external auditor is required to report, such as:
auditor independence;
methods used to account for significant unusual transactions;
material proposed audit adjustments and immaterial adjustments not recorded by
    management;
auditor judgments about the quality of the Company's accounting principles;
management-related issues encountered in performing the audit; and
disagreements with management over the application of accounting principles,
    management's accounting estimates and related matters.
 
·
Review management's "internal control report" to be included in annual report and external auditor's assessment of same.
 
·
Internal control issues, if any.
 
·
Separate in camera meetings with the external auditor and external counsel.
 
·
Annual information form and comparable 40-F.
 
A -9
 
 
·
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.
 
Management’s discussion and analysis

The following analysis provides a detailed explanation of Provident’s operating results for the quarter and year ended December 31, 2006 compared to the quarter and year ended December 31, 2005 and should be read in conjunction with the consolidated financial statements of Provident. This analysis has been prepared using information available up to March 7, 2007.
 
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 services and marketing (“Midstream”). Provident’s COGP business produces crude oil and natural gas from six core areas in the western Canadian sedimentary basin. USOGP produces crude oil and natural gas in Southern California and in Wyoming, U.S.A. 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.

Forward-looking statements

Certain statements included in this analysis constitute forward-looking statements under applicable securities legislation. These statements relate to future events or Provident’s future performance. All statements other than statements of historical fact are forward-looking statements. In some cases, forward-looking statements can be identified by terminology such as "may", "will", "should", "expect", "plan", "anticipate", "believe", "estimate", "predict", "potential", "continue", or the negative of these terms or other comparable terminology. Forward-looking statements or information in this analysis include, but are not limited to, business strategy and objectives, reserve quantities and the discounted present value of future net cash flows from such reserves, net revenue, future production levels, capital expenditures, exploration plans, development plans, acquisition and disposition plans and the timing thereof, operating and other costs, royalty rates, budgeted levels of cash distributions and the performance associated with Provident's natural gas midstream, NGL processing and marketing business. These statements are only predictions. Actual events or results may differ materially. In addition, this analysis may contain forward-looking statements attributed to third party industry sources. Undue reliance should not be placed on these forward-looking statements, as there can be no assurance that the plans, intentions or expectations upon which they are based will occur. By its nature, forward-looking information involves numerous assumptions, known and unknown risks and uncertainties, both general and specific, that contribute to the possibility that the predictions, forecasts, projections and other forward-looking statements will not occur. In addition to other assumptions identified in this analysis, assumptions in respect of forward-looking statements have been made regarding, among other things:
 
 
·
Provident’s ability to benefit from the combination of growth opportunities and the ability to grow through the capital markets;
 
·
Provident’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 Provident, including the effect of proposed taxation of trust distributions;
 
·
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 NGL services, processing and marketing business;
 
·
the growth opportunities associated with the NGL services, processing and marketing business; and
 
·
the nature of contractual arrangements with third parties in respect of Provident's NGL services, processing and marketing business.
 
Although Provident believes that the expectations reflected in the forward-looking statements are reasonable, there can be no assurance that such expectations will prove to be correct. Provident can not guarantee future results, levels of activity, performance, or achievements. Moreover, neither the Trust, Provident nor any other person assumes responsibility for the accuracy and completeness of the forward-looking statements. Some of the risks and other factors, some of which are beyond Provident's control, which could cause results to differ materially from those expressed in the forward-looking statements contained in this analysis include, but are not limited to:
 
 
·
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 proposed taxation of trust distributions;
 
·
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; and 
  · third party performance of obligations under contractual arrangements.

Statements relating to "reserves" or "resources" are deemed to be forward-looking statements, as they involve the implied assessment, based on certain estimates and assumptions that the resources and reserves described can be profitably produced in the future. Readers are cautioned that the foregoing list of factors is not exhaustive. The forward-looking statements contained in this analysis are expressly qualified by this cautionary statement. Subject to Provident’s obligations under applicable securities laws, Provident is not under any duty to update any of the forward-looking statements after the date of this analysis to conform such statements to actual results or to changes in Provident’s expectations.
 
 
Consolidated financial highlights
 
 
Three months ended December 31,
Year ended December 31,
  
Consolidated
                             
($ 000s except per unit data)
    
2006
 
2005
  
% Change
  
 2006
 
2005
 
% Change
  
                              
Revenue (net of royalties and financial
derivative instruments)
      
$
548,086
  
$
442,687
    
24
 
$
2,187,253
 
$
1,360,274
    
61
 
                                           
Cash flow from COGP operations (1)
     
$
48,574
  
$
51,992
    
(7
)
$
185,328
 
$
185,129
    
-
 
Cash flow from USOGP operations (1)
        
13,573
   
16,014
   
(15
)
  
62,970
   
59,821
   
5
 
Cash flow from midstream services
and marketing (1)
        
60,532
   
28,292
   
114
   
184,366
   
66,238
   
178
 
Total cash flow from operations (1)
      
$
122,679
  
$
96,298
    
27
 
$
432,664
 
$
311,188
    
39
 
Per weighted average unit – basic (2)
      
$
0.58
  
$
0.57
    
2
 
$
2.20
 
$
1.95
    
13
 
Per weighted average unit – diluted (3)
      
$
0.58
  
$
0.51
    
14
 
$
2.20
 
$
1.95
    
13
 
Declared distributions to unitholders
      
$
75,573
  
$
62,646
    
21
 
$
283,465
 
$
230,714
    
23
 
Per unit (2)
      
$
0.36
  
$
0.36
    
-
 
$
1.44
 
$
1.44
    
-
 
Percent of cash flow from operations paid
out as declared distributions
        
62
%
  
65
%
  
(5
)
  
66
%
  
74
%
  
(12
)
Net (loss) income
      
$
(25,501
)
$
54,501
    
-
 
$
140,920
 
$
96,926
    
45
 
Per weighted average unit – basic (2)
      
$
(0.12
)
$
0.32
    
-
 
$
0.72
 
$
0.61
    
18
 
Per weighted average unit – diluted (3)
      
$
(0.12
)
$
0.32
    
-
 
$
0.72
 
$
0.61
    
18
 
Capital expenditures
     
$
60,911
  
$
51,011
    
19
 
$
190,433
 
$
156,499
    
22
 
Midstream NGL acquisition
      
$
(1,264
)
$
772,303
    
-
  
$
1,036
 
$
772,303
    
(100
)
Nautilus acquisition
      
$
-
  
$
-
    
-
 
$
-
  
$
91,420
    
(100
)
Property acquisitions
      
$
8,649
  
$
1,266
    
583
 
$
480,357
 
$
586
    
81,872
 
Property dispositions
      
$
(29
)
$
461
    
-
 
$
(1,268
)
$
45,100
    
-
 
Weighted average trust units outstanding (000s)
                                         
- Basic(2)
        
209,826
   
169,609
   
24
   
196,627
   
159,316
   
23
 
- Diluted(3)
        
210,113
   
188,036
   
12
   
196,914
   
159,686
   
23
 
 
 
Consolidated
  
As at December 31,
      
($ 000s)
  
2006
  
2005
  
% Change
  
Capitalization
                    
Long-term debt
  
$
988,785
  
$
884,604
    
12
 
Unitholders’ equity
  
$
1,542,974
  
$
1,404,826
    
10
 
(1) Represents cash flow from operations before changes in working capital and site restoration expenditures.
(2) Excludes exchangeable shares.
(3) Includes dilutive impact of unit options, exchangeable shares and convertible debentures.

Operational highlights 
 

   
Three months ended December 31,
  
Year Ended December 31,
  
Consolidated
                               
       
2006
  
2005
  
% Change
  
 2006
  
2005
  
% Change
  
                                
Oil and Gas Production
                              
Daily production
                               
Light/medium crude oil (bpd)
          
13,899
   
14,051
   
(1
)
  
14,114
   
14,979
   
(6
)
Heavy oil (bpd)
          
1,838
   
3,195
   
(42
)
  
2,057
   
4,358
   
(53
)
Natural gas liquids (bpd)
          
1,345
   
1,653
   
(19
)
  
1,419
   
1,596
   
(11
)
Natural gas (mcfd)
          
100,029
   
73,363
   
36
   
84,891
   
77,095
   
10
 
Oil equivalent (boed)(1)
          
33,753
   
31,126
   
8
   
31,739
   
33,782
   
(6
)
Average selling price (before realized financial derivative instruments)
                                      
Light/medium crude oil ($/bbl)
        
$
54.59
  
$
55.31
    
(1
)
$
60.32
 
$
54.69
    
10
 
Heavy oil ($/bbl)
        
$
25.82
  
$
28.62
    
(10
)
$
36.80
 
$
31.33
    
17
 
Corporate oil blend ($/bbl)
        
$
51.23
  
$
50.36
    
2
 
$
57.33
 
$
49.43
    
16
 
Natural gas liquids ($/bbl)
        
$
47.49
  
$
49.44
    
(4
)
$
51.98
 
$
49.09
    
6
 
Natural gas ($/mcf)
        
$
6.71
  
$
11.44
    
(41
)
$
6.66
 
$
8.43
    
(21
)
Oil equivalent ($/boe)(1)
        
$
45.65
  
$
57.50
    
(21
)
$
49.35
 
$
49.86
    
(1
)
Field netback (before realized financial derivative instruments) ($/boe)
  
$
23.96
  
$
34.63
    
(31
)
$
27.93
 
$
29.97
    
(7
)
Field netback (including realized financial derivative instruments) ($/boe)
  
$
25.58
  
$
28.33
    
(10
)
$
28.09
 
$
24.73
    
14
 
                                             
Midstream services and marketing
                                            
Managed NGL volumes (bpd)
          
145,732
   
77,100
   
89
   
153,020
   
64,740
   
136
 
EBITDA (000s)(2)
        
$
74,422
  
$
29,566
    
152
 
$
219,631
 
$
70,689
    
211
 
(1) Provident reports oil equivalent production converting natural gas to oil on a 6:1 basis.
(2) EBITDA is earnings before interest, taxes, depletion, depreciation, accretion and other non-cash items.
 
Fourth quarter highlights

The fourth quarter highlights section provides commentary on the fourth quarter 2006 results compared to the fourth quarter of 2005. Definitions of terms used in this section, as appropriate, are defined in the year over year section of the Management’s Discussion and Analysis following later in this press release.
 
Consolidated cash flow from operations before changes in working capital and site restoration expenditures (“Cash Flow”) and cash distributions
 
Consolidated
  
Three months ended December 31,
  
($ 000s, except per unit data)
      
2006
  
2005
  
% Change
  
Revenue, Cash Flow and Distributions
                  
Revenue (net of royalties and financial derivative instruments)
        
$
548,086
  
$
442,687
    
24
 
Cash flow from operations before changes in working capital and site restoration expenditures
  
$
122,679
  
$
96,298
    
27
 
Per weighted average unit - basic (1)
        
$
0.58
  
$
0.57
    
2
 
Per weighted average unit - diluted (2)
        
$
0.58
  
$
0.51
    
14
 
Declared distributions
       
$
75,573
  
$
62,646
    
21
 
Per Unit
          
0.36
   
0.36
   
-
 
Percent of cash flow distributed
          
62
%
  
65
%
  
(5
)
(1) Excludes exchangeable shares.
(2) Includes the dilutive impact of unit options, exchangeable shares and convertible debentures.

Fourth quarter 2006 cash flow was $122.7 million, 27 percent above the $96.3 million of cash flow recorded in the fourth quarter of 2005. COGP 2006 fourth quarter cash flow was $48.6 million, a seven percent decrease from the $52.0 million recorded in the comparable 2005 quarter. The main drivers for the COGP decrease were the lower realized natural gas price due to the decrease in the AECO natural gas index price, and natural production declines in crude oil and liquids. The cash flow decrease was partially offset by the addition of the Rainbow assets acquired on August 31, 2006 which increased overall production compared to the 2005 fourth quarter, as well as the successful drilling programs in Southwest Saskatchewan and activities in West Central and Southern Alberta core areas. The Rainbow assets represent COGP’s new core area, Northwest Alberta. The Midstream business unit added $60.5 million to fourth quarter 2006 cash flow, 114 percent above the $28.3 million recorded in the comparable 2005 quarter. This increase is attributable to the Midstream NGL Acquisition in December of 2005 and the result of increased product margins in fourth quarter 2006 over 2005. Cash flow from operations in USOGP decreased 15 percent to $13.6 million compared to cash flow of $16.0 million in the comparable 2005 quarter. Improved netbacks were more than offset by increases to cash general and administrative expense as well as higher interest expense.

Declared distributions in the fourth quarter of 2006 totaled $75.6 million, 62 percent of cash flow from operations. This compares to $62.6 million of declared distributions in fourth quarter 2005, 65 percent of cash flow from operations.
 
Net (loss) income
 
Consolidated
  
Three months ended December 31,
  
($ 000s, except per unit data)
      
2006
  
2005
  
% Change
  
                   
Net (loss) income
        
$
(25,501
)
$
54,501
    
-
 
Per weighted average unit
– basic(1)
        
$
(0.12
)
$
0.32
    
-
 
Per weighted average unit
– diluted(2)
        
$
(0.12
)
$
0.32
    
-
 
(1) Based on weighted average number of trust units outstanding.
(2) Based on weighted average number of trust units outstanding including the dilutive impact of the unit option plan, exchangeable shares and convertible debentures.
 
Net (loss) income for the fourth quarter of 2006 decreased to a loss of $25.5 million compared to $54.5 million of net income in the comparable 2005 quarter. A 36 percent increase in earnings before interest, taxes, depletion, depreciation, accretion and other non-cash items (EBITDA) due to the Midstream NGL Acquisition was more than offset by a $56.2 million change in unrealized loss on financial derivative instruments and higher depletion, depreciation and accretion (DD&A) charges as well as higher interest expense, both reflecting the larger asset base and increased capitalization due to the Midstream NGL Acquisition and the Rainbow asset acquisition.

The COGP business segment had a net loss of $8.2 million compared to 2005 fourth quarter net income of $34.9 million. The net loss in the fourth quarter of 2006 was a result of a lower EBITDA reflecting the lower realized natural gas price due to the decrease in the AECO natural gas index price combined with a $24.0 million change in unrealized loss on financial derivative instruments.

The Midstream segment recognized a net loss of $11.0 million in the fourth quarter of 2006, as compared to $24.1 million of net income in the fourth quarter of 2005. Midstream results include EBITDA of $74.4 million in 2006 as compared to $29.6 million in fourth quarter 2005. This significant improvement in EBITDA is attributable to the Midstream NGL acquisition completed in December 2005. This acquisition has extended Provident’s participation in the NGL value chain through increased managed volumes. Midstream EBITDA reflects an increase in fees for services, fixed margin extraction and equity margin on marketed NGLs. The significant improvement in Midstream EBITDA is also the result of an increase in propane plus margins in 2006 over 2005. Offsetting this strong EBITDA are unrealized losses on outstanding financial derivative instruments amounting to $28.7 million for the fourth quarter of 2006 (2005 - $0.9 million gain). Under generally accepted accounting principles, these unrealized “mark-to-market” amounts, which relate to financial instruments with effective periods ranging over the next five years from 2007 through 2011, are required to be recognized in the financial statements of Provident, affecting current period net income (see “Commodity price risk management program”). In addition, higher DD&A charges of $16.6 million compared to $4.2 million in 2005, and significantly higher interest expense of $9.6 million versus $1.1 million in 2005 are the result of a larger asset base and increased capitalization due to the Midstream NGL Acquisition.
 
USOGP generated a net loss of $6.3 million in the fourth quarter of 2006 with a comparative net loss of $4.5 million for 2005. A five percent decrease in EBITDA, higher DD&A reflecting a fourth quarter adjustment to reserves, and higher non-cash unit based compensation were partially offset by a decrease in future tax expense of $13.9 million in the fourth quarter of 2006, compared to the fourth quarter of 2005.
 
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:
 
Consolidated
  
Three months ended December 31,
  
EBITDA Reconciliation
                  
($ 000s)
      
2006
  
2005
  
% Change
  
EBITDA
        
$
140,919
  
$
103,542
    
36
 
Adjusted for:
                          
Interest and non-cash expenses excluding unrealized (loss) gain on financial derivative instruments
  
(116,392
)
  
(56,828
)
  
105
 
Unrealized (loss) gain on financial derivative instruments
          
(24,293
)
  
31,943
    
-
 
Income before taxes and non-controlling interests
    
$
234
  
$
78,657
    
(100
)
 
 
Taxes
 
Consolidated
  
Three months ended December 31,
  
($ 000s)
      
2006
  
2005
  
% Change
  
Capital taxes
       
$
452
  
$
1,103
    
(59
)
Current and withholding tax expense (recovery)
          
1,433
   
(1,296
)
  
-
 
Future income tax expense
          
21,253
   
23,327
   
(9
)
         
$
23,138
  
$
23,134
    
-
 

Capital taxes in the fourth quarter totaled $0.5 million, a decrease of $0.6 million from the $1.1 million recorded in the fourth quarter of 2005. The decrease reflects an adjustment for the legislated phase-out of the large corporations tax, netted against the increase in the Saskatchewan resource surcharge that is sensitive to crude oil prices.

The current and withholding tax expense is $1.4 million in the fourth quarter of 2006 with a comparative recovery of $1.3 million in the fourth quarter of 2005. These taxes arise from Provident’s U.S. based operations and reflect an increase in 2006 income subject to tax, primarily in U.S. Midstream operations.
 
The 2006 fourth quarter future tax expense of $21.3 million compares to an expense of $23.3 million in the fourth quarter of 2005. The future tax expense in the fourth quarter of 2006 resulted from utilizing tax pools in both Canada and the U.S.A., reflecting the increased 2006 income subject to tax, primarily in Midstream operations.
 
Interest expense
 
Consolidated
  
Three months ended December 31,
  
($ 000s)
      
2006
  
2005
  
% Change
  
                   
Interest on bank debt
        
$
11,162
  
$
4,100
    
172
 
Interest on convertible debentures
          
5,146
   
3,651
   
41
 
Total cash interest
       
$
16,308
  
$
7,751
    
110
 
Non-cash accretion expense - convertible debentures
          
654
   
(752
)
  
-
 
Total interest including accretion on convertible debentures
  
$
16,962
  
$
6,999
    
142
 
 
Cash interest expense increased for the quarter as compared to the same quarter in 2005 due to the increase in the overall size of Provident, with commensurate increases in debt levels. Increased debt levels are a direct result of the Midstream NGL acquisition in late 2005 and the third quarter 2006 Rainbow asset acquisition.
 
 
Commodity price risk management program

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

In accordance with the Trust’s credit policy, the Trust mitigates associated credit risk by limiting financial derivative transactions to counterparties within approved credit limits.

In the Midstream business, production margins are impacted by the spread between the purchase cost of natural gas and sales price of propane, butane and condensate. Financial market liquidity may not provide sufficient or adequate opportunity to directly hedge propane, butane and condensate prices over the longer term. Prices for propane, butane and condensate historically have correlated with prices for crude oil. As a consequence, Provident has entered into natural gas and crude oil financial derivative contracts through 2011 in order to protect production margins in the Midstream business. Short term financial derivative instruments directly fixing propane and butane prices have also been executed.
 
Activity in the Fourth Quarter:

COGP
 
 
 
 
 
 
Volume
 
 
Year
Product
(Buy)/Sell
Terms
Effective Period
2007
Crude Oil
750
Bpd
Participating Swap US $60.00 per bbl (62% above the floor price)
January 1 - December 31
 
 
750
Bpd
Puts US $60.00 per bbl
January 1 - December 31
 
Natural Gas
2,000
Gjpd
Participating Swap Cdn $7.00 per gj (max to 78% above the floor price)
January 1 - March 31
 
 
1,500
Gjpd
Participating Swap Cdn $7.00 per gj (max to 80% above the floor price)
January 1 - March 31,
November 1 - December 31
 
 
3,000
Gjpd
Participating Swap Cdn $6.33 per gj (max to 100% above the floor price)
April 1 - October 31
 
 
3,000
Gjpd
Participating Swap Cdn $6.33 per gj (max to 90% above the floor price)
April 1 - October 31
 
 
6,000
Gjpd
Participating Swap Cdn $6.30 per gj (max to 95% above the floor price)
April 1 - October 31
 
 
1,000
Gjpd
Participating Swap Cdn $6.00 per gj (max to 66% above the floor price)
April 1 - October 31
 
 
2,000
Gjpd
Participating Swap Cdn $6.13 per gj (max to 68% above the floor price)
April 1 - October 31
 
 
5,000
Gjpd
Puts Cdn $6.85 per gj
January 1 - December 31
 
 
9,500
Gjpd
Puts Cdn $6.89 per gj
January 1 - March 31,
November 1 - December 31
 
 
4,000
Gjpd
Puts Cdn $6.75 per gj
November 1 - December 31
 
 
 
 
 
 
USOGP
        
   
Volume
    
Year
Product
(Buy)/Sell
Terms
Effective Period
2007
Crude Oil
250
Bpd
US $60.00 per bbl
January 1 - December 31
   
250
Bpd
Participating Swap US $55.00 per bbl (max to 84% above the floor price)
January 1 - December 31
   
 
 
    
2008
Crude Oil
2,500
Bpd
Participating Swap US $60.00 per bbl (max to 53.3% above the floor price)
July 1 - September 31
   
2,000
Bpd
Participating Swap US $60.00 per bbl (avg of 59% above the floor price)
October 1 - December 31
     
 
    
2009
Crude Oil
2,000
Bpd
Participating Swap US $60.00 per bbl (max to 59% above the floor price)
January 1 - September 30
           
MIDSTREAM
 
 
 
 
 
 
Volume
 
 
Year
Product
(Buy)/Sell
Terms
Effective Period
2007
Crude Oil
500
Bpd
Cdn $74.65 per bbl
April 1 - December 31
 
 
1,750
Bpd
Cdn $73.37 per bbl
January 1 - December 31
 
 
(6,456)
Bpd
US $63.76 per bbl (4)
January 1 - March 31
 
 
(584)
Bpd
Cdn $70.91 per bbl (4)
January 1 - March 31
 
Natural Gas
3,000
Gjpd
Cdn $8.28 per gj
January 1 - January 31
 
 
(3,201)
Gjpd
Cdn $7.70 per gj
January 1 - March 31
 
 
(2,869)
Gjpd
Cdn $7.84 per gj
April 1 - December 31
 
 
(9,812)
Gjpd
Cdn $7.65 per gj
January 1 - December 31
 
Propane
8,143
Bpd
US $0.9648 per gallon (4) (6)
January 1 - March 31
 
 
806
Bpd
US $0.965 per gallon (6) (8)
January 1 - February 28
 
 
1,666
Bpd
US $0.9668 per gallon (6) (8)
January 1 - March 31
 
Normal Butane
746
Bpd
US $1.1044 per gallon (4) (7)
January 1 - March 31
 
Foreign Exhange
 
 
Sell US $912,500 per month @ 1.1491 (5)
January 1 - December 31
 
 
 
 
 
 
2008
Crude Oil
500
Bpd
Costless Collar US $64.00 floor, US $74.50 ceiling
January 1 - September 30
 
 
750
Bpd
Cdn $77.55 per bbl
January 1 - June 30
 
 
1,045
Bpd
Cdn $75.31 per bbl
July 1 - December 31
 
 
1,750
Bpd
Cdn $75.18 per bbl
January 1 - December 31
 
Natural Gas
(10,000)
Gjpd
Cdn $7.96 per gj
January 1 - December 31
 
 
(4,443)
Gjpd
Cdn $8.11 per gj
January 1 - June 30
 
 
(2,965)
Gjpd
Cdn $7.94 per gj
January 1 - September 30
 
 
(5,808)
Gjpd
Cdn $7.87 per gj
July 1 - December 31
 
Foreign Exchange
 
 
Sell US $974,222 per month @ 1.1255 (5)
January 1 - September 30
 
 
 
 
 
 
2009
Crude Oil
250
Bpd
Cdn $77.37 per bbl
January 1 - March 31
 
 
500
Bpd
Cdn $77.42 per bbl
January 1 - June 30
 
 
500
Bpd
Cdn $75.10 per bbl
July 1 - December 31
 
 
250
Bpd
Cdn $76.70 per bbl
July 1 - September 30
 
 
500
Bpd
Cdn $72.46 per bbl
January 1 - December 31
 
Natural Gas
(2,962)
Gjpd
Cdn $8.10 per gj
January 1 - June 30
 
 
(1,481)
Gjpd
Cdn $8.74 per gj
January 1 - March 31
 
 
(2,700)
Gjpd
Cdn $7.64 per gj
January 1 - December 31
 
 
(1,481)
Gjpd
Cdn $7.59 per gj
July 1 - September 30
 
 
(2,776)
Gjpd
Cdn $7.75 per gj
July 1 - December 31
-8-
 
 
MIDSTREAM, continued
 
 
 
 
Volume
 
 
Year
Product
(Buy)/Sell
Terms
Effective Period
 
 
 
 
 
 
2010
Crude Oil
500
Bpd
Cdn $71.07 per bbl
January 1 - December 31
 
Natural Gas
(2,700)
Gjpd
Cdn $7.35 per gj
January 1 - December 31
 
 
 
 
 
 
2011
Crude Oil
250
Bpd
Cdn $66.95 per bbl
January 1 - June 30
 
 
885
Bpd
Cdn $70.99 per bbl
January 1 - September 30
 
 
250
Bpd
Cdn $73.35 per bbl
January 1 - October 31
 
 
250
Bpd
Cdn $72.75 per bbl
January 1 - November 30
 
 
250
Bpd
Costless Collar US $60.00 floor, US $68.10 ceiling
July 1 - September 30
 
 
250
Bpd
Costless Collar US $60.00 floor, US $67.30 ceiling
July 1 - September 30
 
 
500
Bpd
Costless Collar US $56.00 floor, US $75.25 ceiling
July 1 - September 30
 
 
500
Bpd
Costless Collar US $58.00 floor, US $76.20 ceiling
July 1 - September 30
 
 
500
Bpd
Costless Collar US $60.00 floor, US $71.60 ceiling
July 1 - September 30
 
Natural Gas
(1,410)
Gjpd
Cdn $7.12 per gj
January 1 - June 30
 
 
(13,269)
Gjpd
Cdn $6.72 per gj
July 1 - September 30
 
 
(4,955)
Gjpd
Cdn $7.02 per gj
January 1 - September 30
 
 
(1,481)
Gjpd
Cdn $7.25 per gj
January 1 - October 31
 
 
(1,481)
Gjpd
Cdn $7.24 per gj
January 1 - November 30
 
Foreign Exchange
 
 
Sell US $717,600 per month @ 1.0931 (5)
July 1 - September 30
   
 
 
    
(1) The above table represents a number of transactions entered into over an extended period of time.
(2) Natural gas contracts settle against AECO monthly index.
(3) Crude oil contracts settle against NYMEX (New York Mercantile Exchange) WTI (West Texas Intermediate) calendar average.
(4) Conversion of Crude Oil BTU (British Thermal Unit) hedges to Propane
(5) US dollar hedge contracts settled against Bank of Canada noon rate average.
(6) Propane contracts are settled against Belvieu C3 TET (Texas Eastern Transmission)
(7) Normal Butane contracts are settled against Belvieu NC4 NON-TET
(8) Midstream Inventory Hedges
 
Settlement of commodity contracts

The following is a summary of the net cash flow to settle Commodity contracts during the fourth quarter of 2006. For comparative purposes, the 2005 amounts are also summarized.

a) Crude oil

For the quarter ending December 31, 2006, Provident received $1.3 million (2005 - $16.5 million paid) to settle various oil market based contracts on an aggregate volume of 0.7 million barrels (2005 - 0.6 million barrels). As at December 31, 2006 the estimated value of contracts in place if settled at December 31 market prices would have resulted in an opportunity gain of $7.2 million (2005 - $7.1 million opportunity cost).

b) Natural Gas

For the quarter ending December 31, 2006, Provident received $3.7 million (2005 - $4.1 million paid) to settle various natural gas market based contracts on an aggregate volume of 3.7 million gj’s (2005 - 1.5 million gj’s). As at December 31, 2006 the estimated value of contracts in place if settled at December 31 market prices would have resulted in an opportunity gain of $8.6 million (2005 - $6.5 million opportunity cost).

c) Midstream

For the quarter ending December 31, 2006 Provident received $5.4 million (2005 - $1.7 million paid) on midstream margin hedging activities. As at December 31, 2006 the estimated value of contracts in place settled at December 31 market prices would have resulted in an opportunity cost of $68.8 million (2005 - $0.4 million). This value represents our five year hedging plan for Midstream executed in 2006.

d) Foreign exchange contracts

As at December 31, 2006 the estimated value of contracts in place settled at December 31 foreign exchange rates would have resulted in an opportunity gain of $0.1 million (2005 - $0.1 million opportunity cost). The foreign exchange gains have been included as a component of foreign exchange gain and other and allocated to their respective business segments.

 
Provident’s Commodity Price Risk Management activities are also discussed in the year over year section of Management’s Discussion and Analysis and in Note 14 to the consolidated financial statements.
 
COGP segment review

Crude oil price and liquids
 
COGP
  
Three months ended December 31,
  
($ per bbl)
      
2006
  
 2005
  
% Change
  
Oil per barrel
                          
WTI (US$)
        
$
60.21
  
$
60.02
    
-
 
Exchange rate (from US$ to Cdn$)
          
1.14
   
1.17
    
(3
)
WTI expressed in Cdn$
        
$
68.64
  
$
70.22
    
(2
)
                           
Realized pricing before financial derivative instruments
                     
Light/Medium oil
        
$
51.93
  
$
52.28
    
(1
)
Heavy oil
       
$
25.82
  
$
28.62
    
(10
)
Natural gas liquids
       
$
47.46
  
$
49.62
   
(4
)
Crude oil and natural gas liquids
       
$
46.39
  
$
45.44
    
2
 
 
The above prices are net of transportation expense.

In the fourth quarter of 2006 COGP’s realized oil and natural gas liquids price, prior to the impact of financial derivative instruments, increased by two percent to $46.39 per barrel compared to $45.44 per barrel in the fourth quarter of 2005. The 2006 increase in total liquids mix was related to lower conventional heavy oil volumes as a percentage of the total mix, resulting in a higher proportion of production from light/medium oil, which has a higher average price than heavy oil. This was partially offset by a stronger Canadian dollar and wider differentials on heavy oil pricing relative to WTI.

Natural gas price
 
COGP
                  
   
Three months ended December 31,
  
($ per mcf)
      
2006
  
2005
  
% Change
  
                   
AECO monthly index (Cdn$) per mcf
        
$
6.36
  
$
11.67
    
(46
)
Corporate natural gas price per mcf before financial derivative instruments
(Cdn$)
  
$
6.73
  
$
11.40
    
(41
)
 
The above prices are net of transportation expense.

COGP’s fourth quarter 2006 realized natural gas price, prior to the impact of financial derivative instruments, decreased 41 percent as compared to the fourth quarter of 2005, less than the decrease in the benchmark AECO index price of 46 percent. Provident’s gas portfolio includes aggregator contracts sold on a term basis that can differ from the benchmark price and sells to the spot market on monthly or daily indices and receives prices which take into account heat content. Provident’s realized prices and changes in prices can therefore differ from benchmark indices.

Production

 
Three months ended December 31,
COGP
      
 
2006
2005
% Change
Daily production
      
Crude oil    - Light/Medium (bpd)
6,569
6,866
(4)
         - Heavy (bpd)
1,838
3,195
(42)
Natural gas liquids (bpd)
1,331
1,617
(18)
Natural gas (mcfd)
97,489
71,168
37
Oil equivalent (boed) (1)
25,986
23,539
10
(1) Provident reports equivalent production converting natural gas to oil on a 6:1 basis.

 
Production increased 10 percent to 25,986 boed during the fourth quarter of 2006 as compared to 23,539 boed in 2005. The increase was primarily a result of the additional production from the Rainbow assets acquired on August 31, 2006 and the successful drilling programs in Southwest Saskatchewan and activities in West Central and Southern Alberta core areas. Plant restrictions and down time due to cold weather at Northwest Alberta’s Rainbow and Pouce Coupe fields resulted in 550 boed less production than expected in the fourth quarter of 2006. The overall increase in production was partially offset by the natural production declines including higher declines in heavy oil partially offset by drilling and optimization activities. Provident’s production risk is mitigated by not having any single property providing greater than 10 percent of its total production.

Production for the fourth quarter of 2006 was weighted 63 percent natural gas, 30 percent medium/light crude oil and natural gas liquids and seven percent heavy oil. This compared to fourth quarter 2005 production weighted 50 percent natural gas, 36 percent medium/light oil and natural gas liquids and 14 percent heavy oil. Quarter-over-quarter, the change in mix reflected the Rainbow assets acquired on August 31, 2006 which was primarily natural gas production, increased capital spending on natural gas opportunities and natural production declines in the heavy oil areas.

COGP’s production summarized by core areas is as follows:
 
COGP
                
Three months ended
December 31, 2006
West Central
Alberta
Southern
Alberta
Northwest
Alberta
Southeast
Saskatchewan
Southwest
Saskatchewan
 
Lloydminster
 
Other
 
Total
                 
Daily production
                
Crude oil   - Light/Medium (bpd)
1,051
2,172
149
1,602
318
1,245
32
6,569
        - Heavy (bpd)
-
-
-
-
-
1,838
-
1,838
Natural gas liquids (bpd)
1,111
101
94
-
-
22
3
1,331
Natural gas (mcfd)
32,913
22,494
26,928
152
13,364
1,347
291
97,489
Oil equivalent (boed) (1)
7,648
6,022
4,731
1,627
2,545
3,330
83
25,986

COGP
                
Three months ended
December 31, 2005
West Central
Alberta
Southern
Alberta
Northwest
Alberta
Southeast
Saskatchewan
Southwest
Saskatchewan
 
Lloydminster
 
Other
 
Total
                 
Daily production
                
Crude oil - Light/Medium (bpd)
1,057
2,541
-
1,726
337
1,204
1
6,866
- Heavy (bpd)
-
-
-
-
-
3,195
-
3,195
Natural gas liquids (bpd)
1,418
179
-
-
1
19
-
1,617
Natural gas (mcfd)
38,343
22,722
-
196
8,916
978
13
71,168
Oil equivalent (boed) (1)
8,865
6,507
-
1,759
1,824
4,581
3
23,539
(1) Provident reports equivalent production converting natural gas to oil on a 6:1 basis.
 
Internal development activities included 22.0 net wells drilled during the quarter ended December 31, 2006 with a 100 percent success rate as Provident continues with the expanded drilling program announced with the second quarter results. Provident’s most active area in fourth quarter 2006 was southern Saskatchewan, where 12.0 net wells were drilled and focused on the shallow gas drilling program. Southern Alberta continued with its shallow gas drilling resulting in 2.1 net wells drilled. Production results to date have been strong in southern Alberta and Saskatchewan, exceeding internal expectations. Provident expects the production from the above net drills to be placed on production during the first and second quarters of 2007. Northwest Alberta’s activities continued to focus on preparation for the winter drilling program and also drilled 5.4 net wells in 2006. Northwest Alberta was ahead of its planned winter drilling schedule due to effective planning and execution of the drilling program and favourable weather conditions. In Lloydminster, Provident is working to enhance the area cost structure through production optimization and increased water disposal capacity. In west central Alberta, Provident continues with its strategy of farming out high risk exploration land to enhance cash flow and drilled 2.3 net wells in low risk areas. The production in west central Alberta requires relatively less capital to manage its decline. In the majority of Provident’s operated fields, fewer weather-related disruptions were experienced than historically.
 
 
Revenue and royalties
 
COGP
  
Three months ended December 31, 
  
($ 000s except per boe and mcf data)
     
2006
  
2005
  
% Change
  
                   
Oil
                 
Revenue
        
$
35,754
  
$
41,440
    
(14
)
Realized loss on financial derivative instruments
          
(653
)
  
(11,651
)
  
(94
)
Royalties (net of ARTC)
          
(6,651
)
  
(8,969
)
  
(26
)
Net revenue
        
$
28,450
  
$
20,820
    
37
 
Net revenue (per barrel)
        
$
36.78
  
$
22.49
    
64
 
Royalties as a percentage of revenue
          
18.6
%
  
21.6
%
      
                           
Natural gas
                         
Revenue
        
$
60,337
  
$
74,623
    
(19
)
Realized gain (loss) on financial derivative instruments
          
3,802
   
(1,521
)
  
-
 
Royalties (net of ARTC)
          
(11,680
)
  
(15,503
)
  
(25
)
Net revenue
        
$
52,459
  
$
57,599
    
(9
)
Net revenue (per mcf)
        
$
5.85
  
$
8.80
    
(34
)
Royalties as a percentage of revenue
          
19.4
%
  
20.8
%
      
                           
Natural gas liquids
                         
Revenue
        
$
5,811
  
$
7,382
    
(21
)
Royalties
          
(1,229
)
  
(2,013
)
  
(39
)
Net revenue
        
$
4,582
  
$
5,369
    
(15
)
Net revenue (per barrel)
        
$
37.42
  
$
36.09
    
4
 
Royalties as a percentage of revenue
          
21.1
%
  
27.3
%
      
                           
Total
                         
Revenue
        
$
101,902
  
$
123,445
    
(17
)
Realized gain (loss) on financial derivative instruments
          
3,149
   
(13,172
)
  
-
 
Royalties (net of ARTC)
          
(19,560
)
  
(26,485
)
  
(26
)
Net revenue
       
$
85,491
  
$
83,788
    
2
 
Net revenue per boe
        
$
35.76
  
$
38.69
    
(8
)
Royalties as a percentage of revenue
          
19.2
%
  
21.5
%
      
Note: the above revenue, net revenue and net revenue per boe figures are presented net of transportation expense.
 
Quarter over quarter, 2006 COGP production revenue was $101.9 million, a decrease of 17 percent from $123.4 million in 2005. The decrease in revenue is a result of a 41 percent decrease in Provident’s realized natural gas price due to the decrease in the AECO natural gas index price offset by higher overall production resulting from the addition of the Rainbow assets acquired on August 31, 2006. Total royalties as a percentage of revenue decreased to 19.2 percent primarily due to a reduction in rates from capital spending incentives. The preceding factors, as well as the change in realized gain of financial derivative instruments account for net revenue of $85.5 million in the fourth quarter of 2006, two percent above the $83.8 million recorded in the fourth quarter of 2005. Net revenue per boe in the fourth quarter of 2006 was $35.76 per boe, a decrease of eight percent from $38.69 per boe in the fourth quarter of 2005. The per boe decrease was a result of the preceding factors.

Production expenses
 
COGP
  
Three months ended December 31,
  
($ 000s, except per boe data)
      
2006
  
2005
  
% Change
  
                   
Production expenses
        
$
28,302
  
$
23,437
    
21
 
Production expenses (per boe)
        
$
11.84
  
$
10.82
    
9
 

Fourth quarter 2006 production expenses increased 21 percent to $28.3 million from $23.4 million in the comparable 2005 quarter due to increased production volumes primarily as a result of the Rainbow acquisition. However, on a boe basis quarter over quarter production expenses have increased by nine percent to $11.84 per boe from $10.82 per boe in the comparable 2005 quarter. Cost increases included higher than expected costs for
 
electricity and adjustments related to prior periods by operators on non-operated properties. In addition, costs have increased in fuel, chemicals, well servicing, maintenance and fluid hauling to reflect higher commodities prices and labour costs.

Operating netback

COGP
  
Three months ended December 31,
  
($ per boe)
      
2006
  
2005
  
% Change
  
Netback per boe
                  
Gross production revenue
        
$
42.62
  
$
57.00
    
(25
)
Royalties (net of ARTC)
          
(8.18
)
  
(12.23
)
  
(33
)
Operating costs
          
(11.84
)
  
(10.82
)
  
9
 
Field operating netback
        
$
22.60
  
$
33.95
    
(33
)
Realized gain (loss) on financial derivative instruments
          
1.32
   
(6.08
)
  
-
 
Operating netback after realized financial derivative instruments
        
$
23.92
  
$
27.87
    
(14
)

COGP operating netbacks have transportation expense netted against gross production revenue.
 
The fourth quarter 2006 field operating netback of $22.60 per boe was 33 percent below the $33.95 per boe in the comparable quarter in 2005. The field operating netback reflects COGP’s lower realized price for natural gas and increased operating costs combined with a shift in COGP’s production mix to include more natural gas. Royalties, which are price sensitive, decreased by 33 percent on a boe basis reflecting the lower prices, prior to the impact of hedging. The fourth quarter 2006 operating netback after financial derivative instruments decreased by 14 percent to $23.92 from $27.87 reflecting the preceding factors as well as the 2006 fourth quarter gains on financial derivative instruments of $1.32 per boe compared to a loss of $6.08 per boe in the comparable quarter in 2005.

General and administrative
 
COGP
  
Three months ended December 31,
  
                   
($ 000s, except per boe data)
      
2006
  
2005
  
% Change
  
                   
Cash general and administrative
        
$
6,410
  
$
3,727
    
72
 
Non-cash unit based compensation
          
1,182
   
1,885
    
(37
)
         
$
7,592
  
$
5,612
    
35
 
                           
Cash general and administrative (per boe)
        
$
2.68
  
$
1.72
    
56
 

Cash general and administrative expenses for COGP in the fourth quarter increased 72 percent to $6.4 million from $3.7 million recorded in the 2005 comparable quarter. On a boe basis the cash general and administrative expenses recorded in fourth quarter 2006 increased 56 percent to $2.68 from $1.72 in the fourth quarter of 2005. The increase in cash general and administrative expenses reflects additional costs associated with a more competitive landscape affecting the cost of hiring and compensating employees and consultants, as well as increases in rent, insurance and compliance and reporting costs, including costs relating to implementation of procedures and documentation in connection with the U.S. Sarbanes-Oxley Act.

COGP operations are capable of absorbing additional production, particularly in existing core areas, with little impact on cash general and administrative expenses.
 
 
Capital expenditures
 
COGP
Three months ended December 31,
  
($ 000s)
    
2006
  
2005
  
Capital expenditures - by area
            
West central Alberta
      
$
3,968
  
$
2,282
  
Southern Alberta
        
3,000
   
4,977
 
Northwest Alberta
        
4,598
   
-
 
Southeast Saskatchewan
        
384
   
1,006
 
Southwest Saskatchewan
        
4,006
   
10,925
 
Lloydminster
      
1,738
   
2,497
 
Office and other
        
581
   
(13
)
Total additions
      
$
18,275
  
$
21,674
  
                   
Capital expenditures - by category
                  
Geological, geophysical and land
      
$
1,067
  
$
141
  
Drilling, recompletions, and workovers
        
14,988
   
12,006
 
Facilities and equipment
        
1,365
   
9,449
 
Other capital
        
855
   
78
 
Total additions
      
$
18,275
  
$
21,674
  
                   
Property acquisitions
      
$
8,649
  
$
1,266
  
Property dispositions
      
$
(29
)
$
461
  

In the fourth quarter of 2006, Provident’s COGP business unit spent $18.3 million on capital expenditures. COGP spent $4.6 million in the new area, Northwest Alberta, primarily on drilling activities associated with the winter drilling program which was ahead of schedule due to favourable weather conditions and advanced planning. In the Southeast and Southwest Saskatchewan core areas $4.4 million was spent primarily on shallow gas drilling. Facility work ($0.3 million) in the area focused on infrastructure to tie-in future shallow gas production in Southwest Saskatchewan. In Southern Alberta $3.0 million was spent on drilling activities and recompletions ($2.3 million) and mineral rights acquisitions ($0.6 million). In West central Alberta $4.0 million was spent largely on non-operated drilling ($2.6 million) and facility work ($0.8 million). In the Lloydminster core area $1.7 million was spent primarily on drilling and recompletion activities.
 
In the fourth quarter of 2006, COGP also spent $8.6 million on property acquisitions primarily on acquiring additional working interests in Northwest Alberta ($6.7 million) and in Southern Alberta ($1.7 million).

Provident’s COGP business unit spent $21.7 million in the fourth quarter of 2005 on various drilling, re-completing, optimization and facility projects.

Depletion, depreciation and accretion (DD&A)
 
COGP
Three months ended December 31, 
  
($ 000s, except per boe data)
    
2006
  
2005
  
% Change
  
                 
DD&A
      
$
58,617
  
$
33,809
    
73
  
DD&A (per boe)
      
$
24.52
  
$
15.61
    
57
  
 
The COGP DD&A rate of $24.52 per boe for the fourth quarter of 2006 increased by 57 percent compared to $15.61 per boe for the fourth quarter of 2005. The increase was primarily as a result of the Rainbow asset acquisition. Additions to property, plant and equipment of $660.4 million for the acquisition include $185.7 million due to the recording of future income taxes. This, combined with higher net per boe reserve acquisition costs, resulted in increased per boe DD&A.

Accretion expense associated with asset retirement obligations was $0.5 million in the fourth quarter of 2006 compared to $0.5 million in the fourth quarter of 2005.
 
USOGP Segment Review

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

In the fourth quarter of 2006, Provident, through its USOGP subsidiaries, completed its initial public offering (“IPO”) of 6.9 million units at U.S. $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. Selected producing assets in the Los Angeles basin in California and in Wyoming were transferred to the MLP. The MLP operates approximately two-thirds of existing USOGP production and approximately one-half of USOGP reserves. The previously existing subsidiary (“BreitBurn”) continues to operate some Los Angeles basin assets at West Pico and the Orcutt field (which is the site of the steam-assisted diatomite pilot project). At December 31, 2006 the Trust indirectly owns approximately 66 percent of the MLP and 96 percent of BreitBurn. The MLP and BreitBurn continue to be managed by the management team which operated the USOGP business unit prior to the IPO. The USOGP segment includes the consolidated results of the MLP and BreitBurn. Non-controlling interests include the public ownership in the MLP, 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 the second quarter of 2006.

USOGP Pricing
 
   
Three month ended December 31,
  
USOGP
      
2006
  
2005
  
% Change
  
Realized pricing before financial derivative instruments
                  
Light/medium crude oil and natural gas liquids (Cdn$ per bbl)
        
$
56.96
  
$
58.11
    
(2
)
Natural gas (Cdn$ per mcf)
        
$
5.87
  
$
12.97
    
(55
)

The majority of USOGP oil production is light, sweet crude that attracts smaller differentials to benchmark prices relative to heavier blends. Realized crude oil and natural gas liquids pricing before financial derivative instruments in the fourth quarter of 2006 was comparable with the fourth quarter of 2005. WTI in the fourth quarter of 2006 was U.S. $60.21 compared to U.S. $60.02 in the fourth quarter of 2005. Oil production from the Wyoming properties is a heavier blend of crude oil that attracts wider differentials from WTI pricing. Production from Wyoming properties represents approximately 32 percent of fourth quarter 2006 production.

Realized natural gas pricing saw a 55 percent decrease to $5.87 per mcf in the fourth quarter of 2006 when compared to the fourth quarter of 2005. Natural gas represents approximately five percent of total boe production of USOGP.

Production
 
 
Three months ended December 31,
  
USOGP
  
2006
  
2005
  
% Change
  
               
Daily production - by product
              
Crude oil - Light/Medium (bpd)
      
7,330
   
7,185
    
2
 
Natural gas liquids (bpd)
      
14
   
36
    
(61
)
Natural gas (mcfd)
      
2,540
   
2,195
    
16
 
Oil equivalent (boed) (1)
      
7,767
   
7,587
    
2
 
(1) Provident reports equivalent production converting natural gas to oil on a 6:1 basis.
 
 
Three months ended December 31,
  
USOGP
  
2006
  
2005
  
% Change
  
               
Daily Production - by area (boed) (1)
              
Los Angeles
      
3,772
   
3,974
    
(5
)
Santa Maria - Orcutt
      
1,528
   
1,356
    
13
 
Wyoming
      
2,467
   
2,257
    
9
 
       
7,767
   
7,587
    
2
 
(1) Provident reports equivalent production converting natural gas to oil on a 6:1 basis.
 
USOGP production increased 180 boe per day or two percent in the fourth quarter of 2006 when compared to the fourth quarter of 2005. The increase is primarily attributable to successful optimization and drilling projects partially offset by the low natural declines that reflect the long life nature of these assets.

Revenue and royalties

The following table outlines USOGP revenue and royalties by product line. The table excludes revenues earned from operating certain properties ($0.2 million in 2006 and $0.3 million in 2005) on behalf of third parties.
 
USOGP
  
Three months ended December 31,
  
                   
($ 000s, except per boe and mcf amounts)
  
 
  
2006 
  
2005
  
% Change
  
                   
Oil
                 
Revenue
        
$
38,546
  
$
38,583
    
-
 
Realized gain (loss) on financial derivative instruments
          
1,892
   
(4,875
)
  
-
 
Royalties
         
(3,771
)
  
(3,703
)
  
2
 
Net revenue
        
$
36,667
  
$
30,005
    
22
 
Net revenue (per bbl)
        
$
54.37
  
$
45.39
    
20
 
Royalties as a percentage of revenue
          
9.8
%
  
9.6
%
       
                           
Natural gas
                         
Revenue
        
$
1,373
  
$
2,620
    
(48
)
Royalties
          
(184
)
  
(370
)
  
(50
)
Net revenue
        
$
1,189
  
$
2,250
    
(47
)
Net revenue (per mcf)
        
$
5.09
  
$
11.14
    
(54
)
Royalties as a percentage of revenue
          
13.4
%
  
14.1
%
       
                           
Natural gas liquids
                         
Revenue
        
$
64
  
$
135
    
(53
)
Royalties
          
(2
)
  
(3
)
  
(33
)
Net revenue
        
$
62
  
$
132
    
(53
)
Net revenue (per bbl)
        
$
48.14
  
$
40.06
    
20
 
Royalties as a percentage of revenue
          
3.1
%
  
2.1
%
       
                           
Total
                         
Revenue
        
$
39,983
  
$
41,338
    
(3
)
Realized gain (loss) on financial derivative instruments
          
1,892
   
(4,875
)
  
-
 
Royalties
         
(3,957
)
  
(4,076
)
  
(3
)
Net revenue
       
$
37,918
  
$
32,387
    
17
 
Net revenue (per boe)
        
$
53.06
  
$
46.40
    
14
 
Royalties as a percentage of revenue
          
9.9
%
  
9.9
%
       

Total production revenue for the fourth quarter of 2006 was $40.0 million or three percent lower than the $41.3 million of revenue in the fourth quarter of 2005. The decrease was primarily driven by lower realized natural gas prices in the fourth quarter of 2006 when compared to the fourth quarter of 2005. Total net revenue increased $5.5 million or 17 percent in the fourth quarter of 2006 compared to the fourth quarter of 2005 primarily driven by a $6.8 million positive change in realized gains on financial derivative instruments.

Production expenses

USOGP 
Three months ended December 31,
  
($ 000s, except per boe amounts)
    
2006
  
2005
  
% Change
  
Production expenses
      
$
15,534
  
$
11,510
    
35
 
Production expenses (per boe)
      
$
21.74
  
$
16.49
    
32
 
 
Production expenses increased 35 percent to $15.5 million in the fourth quarter of 2006 compared to $11.5 million for the comparable quarter in 2005. Operating costs per boe have increased 32 percent to $21.74 in the fourth quarter of 2006 from $16.49 in the comparable quarter in 2005. 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 high crude oil prices.
 
Operating netback
 
USOGP 
  
Three months ended December 31,
  
($ per boe)
      
 
  
2006
  
2005 
  
% Change
  
Netback per boe
                      
Gross production revenue
        
 
 
  
$
55.95
  
$
59.22
    
(6
)
Royalties
         
 
 
  
(5.54
)
  
(5.84
)
  
(5
)
Operating costs
          
 
 
  
(21.74
)
  
(16.49
)
  
32
 
Field Operating Netback
        
 
 
   $
28.67
$
36.89
    
(22
)
Realized gain (loss) on financial derivative instruments
          
 
     2.65    
(6.98
)
  
-
 
Operating netback after realized financial derivative instruments
        
 
 
   $
31.32
  
$
29.91
    
5
 
 
The fourth quarter 2006 field operating netback of $28.67 per boe was 22 percent below the $36.89 per boe in the comparable quarter of 2005. The reduction reflects lower realized natural gas prices and increased operating costs. The fourth quarter 2006 operating netback after realized financial derivative instruments of $31.32 per boe is five percent higher than the $29.91 per boe for the fourth quarter of 2005 reflecting the preceding factors offset by realized gains on financial derivative instruments.

General and administrative

USOGP 
Three months ended December 31,
  
($ 000s, except per boe amounts)
    
2006
  
 2005
  
% Change
  
Cash general and administrative
      
$
6,839
  
$
4,525
    
51
 
Non-cash unit based compensation
        
7,800
   
2,000
    
290
 
       
$
14,639
  
$
6,525
    
124
 
Cash general and administrative (per boe)
      
$
9.57
  
$
6.48
    
48
 

Cash general and administrative expenses in the fourth quarter of $6.8 million or $9.57 per boe is 51 percent higher than the fourth quarter of 2005. The increase is due to increased costs associated with compliance (including costs associated with the implementation of procedures and documentation to be in compliance with the U.S. Sarbanes-Oxley Act), increased corporate general and administrative allocations to USOGP operations and increased staffing levels, as well as legal and consulting costs in connection with the initial public offering of the MLP.

Non-cash unit based compensation expense was $7.8 million in the fourth quarter of 2006 compared to $2.0 million in the fourth quarter of 2005. The increase in incentive plan costs is primarily driven by the initial public offering of the MLP completed in the fourth quarter of 2006.
 
 
Capital expenditures
 
USOGP
  
Three months ended December 31,
  
($ 000s)
      
2006
  
2005
  
               
Capital expenditures - by category
              
Geological, geophysical and land
        
$
104
  
$
409
  
Drilling, recompletions, and workovers
          
6,796
   
5,169
 
Facilities and equipment
          
5,365
   
5,802
 
Other capital
          
2,049
   
144
 
Total additions
        
$
14,314
  
$
11,524
  
                     
Capital expenditures - by area (boed)
                    
Los Angeles
          
2,631
   
6,125
  
Santa Maria - Orcutt
          
7,378
   
2,122
  
Wyoming
          
2,157
   
2,718
  
Other capital
          
2,148
   
559
  
           
14,314
   
11,524
  
                     
Property acquisitions
        
$
-
  
$
-
  
Property dispositions
        
$
-
  
$
-
  
 
USOGP capital expenditures for the fourth quarter of 2006 totaled $14.3 million. Of this total, $9.1 million was directed at drilling, optimization and facility upgrades at West Pico, Santa Fe Springs and Orcutt. $2.2 million was directed at drilling and optimization work in Wyoming. $1.3 million was directed at optimization projects at smaller fields as well as head office related capital expenditures and $1.7 million was directed at a real estate development project initiated in the second quarter.

Depletion, depreciation and accretion (DD&A)

USOGP 
  
Three months ended December 31,
  
($ 000s, except per boe amounts)
      
2006
  
2005
 
% Change
  
                   
DD&A
        
$
9,269
  
$
6,622
    
40
 
DD&A (per boe)
        
$
12.97
  
$
9.49
    
37
 

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 is up $3.48 or 37 percent from the fourth quarter of 2005. This is primarily associated with a year-end depletion rate adjustment reflecting 2006 capital expenditures as well as changes in reserves.
 
Midstream services and marketing business segment review

Midstream NGL acquisition

The $773 million Midstream NGL Acquisition, which closed on December 13, 2005, included NGL extraction plants, pipelines, storage and fractionation facilities, distribution facilities, and contracts including marketing, supply and transportation arrangements, and NGL marketing infrastructure. This acquisition has extended Provident’s involvement in the NGL value chain. Results in 2005 included NGL fee for service, fixed margin extraction, equity margin on marketed NGLs, and margin on crude oil marketing contracts. The crude oil marketing contracts were disposed in May 2005, thus 2006 results include an increase in fees for services, fixed margin extraction and equity margin on marketed NGLs.
 
 
Operations - managed NGL volumes
 
Provident managed 145,732 bpd over the fourth quarter of 2006, an 89 percent increase over the 77,100 bpd managed in the fourth quarter of 2005. Managed volumes are NGL products that have been purchased or received for further processing and/or sale. The significant increase in 2006 is a result of the Midstream NGL Acquisition.

Revenues
 
For the fourth quarter of 2006 product sales and services revenues were $441.8 million (2005 - $295.6 million). Revenue figures are after elimination of intersegment transactions. The significant increase in revenue over 2005 is a result of the Midstream NGL Acquisition, and the commissioning of the condensate loading and terminalling facilities in the second quarter of 2006. Product sales relate to the marketing of NGLs and transportation and fractionation contracts (T&F), while service revenue relates to fees earned through NGL processing, marketing, storage and distribution. The majority of NGL revenues are earned pursuant to both long-term contracts and annual evergreen purchase and sales commitments.

In addition to the increased product sales and service revenue, Midstream revenue was increased by $5.4 million in the fourth quarter of 2006 (2005 - $2.6 million loss) due to realized gains on financial derivative instruments. Midstream enters into derivative contracts to assist with margin stabilization on marketed products.

Expenses
 
The cost of goods sold (COGS) was $360.0 million for the fourth quarter of 2006 (2005 - $245.0 million). Cost of goods sold relates to NGL product sales revenue included in product sales and services revenue. COGS include all costs incurred in the production and purchase of NGL specification product for sale. The majority of the natural gas liquids are purchased pursuant to long-term contracts and annual evergreen purchase commitments. The significant increase in COGS over 2005 is a result of the Midstream NGL Acquisition which has resulted in an increased level of activity.

Operating and maintenance expenses were $3.1 million for the fourth quarter of 2006 (2005 - $11.7 million). Fourth quarter 2006 costs include operating costs incurred to process NGLs, and to provide T&F and storage and distribution services to third parties. In prior quarters, operating costs also included costs incurred at the Younger and Redwater facilities for Provident’s own production. These costs are now included in the determination of inventory and cost of goods sold, reflecting the integration of operations after the Midstream NGL Acquisition.

General and administrative expenses were $10.5 million for the fourth quarter of 2006 (2005 - $6.8 million) representing increased costs for compliance activities including costs related to implementation of procedures and documentation in connection with the U.S. Sarbanes-Oxley Act and an increased number of employees since the Midstream NGL Acquisition. Interest expense for the fourth quarter of 2006 was $9.6 million (2005 - $1.1 million) reflecting an increase in capitalization associated with the Midstream NGL Acquisition. Depreciation expense was $16.6 million for the three months ended December 31, 2006 (2005 - $4.2 million) reflecting the larger asset base acquired through the Midstream NGL Acquisition and a $5.8 million impairment write down of capitalized inventory.

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

Fourth quarter 2006 EBITDA of $74.4 million increased $44.8 million or 152 percent from $29.6 million in the fourth quarter of 2005. Cash flow for the fourth quarter of 2006 was $60.5 million, an increase of $32.2 million or 114 percent above the $28.3 million for the fourth quarter 2005. Through the Midstream NGL Acquisition, Provident has expanded its participation in the NGL value chain, which has made a significant contribution to the overall increase in EBITDA and cash flow. In addition, Midstream EBITDA and cash flow benefited from an increase in product margin in the fourth quarter of 2006 over the comparable quarter in 2005.

Management uses EBITDA to analyze the operating performance of the Midstream business unit. EBITDA as presented does not have any standardized meaning prescribed by Canadian GAAP and therefore it may not be comparable with the calculation of similar measures for other entities. EBITDA as presented is not intended to represent operating cash flow or operating profits for the period nor should it be viewed as an alternative to cash flow from operating activities, net earnings or other measures of financial performance calculated in accordance with Canadian GAAP. All references to EBITDA throughout this report are based on earnings before interest, taxes, depletion, depreciation, accretion, and other non-cash items (“EBITDA”).
 
Capital expenditures
 
Midstream capital expenditures for the fourth quarter of 2006 totaled $28.3 million. $6.0 million of the capital was spent on the new condensate offloading facilities and truck terminals at Redwater. An additional $9.2 million was spent on the initial drilling of two new Redwater storage caverns expected to be completed in 2009. $11.3 million was also spent to acquire an additional 7.5% interest in the Provident Empress NGL Extraction plant. The remaining $1.8 million relates to sustaining capital requirements.
 
 
2006 Year end results
 
Consolidated cash flow from operations before changes in working capital and site restoration expenditures (“Cash Flow”) and cash distributions
 

Consolidated
  
Year ended December 31,
  
($ 000s, except per unit data)
      
2006
  
2005
 
% Change
  
Revenue, Cash Flow and Distributions
                  
Revenue (net of royalties and financial derivative instruments -
see Note 8 to the consolidated financial statements)
$
2,187,253
  
$
1,360,274
    
61
 
Cash flow from operations before changes in working capital and site
restoration expenditures
  
$
432,664
  
$
311,188
    
39
 
Per weighted average unit - basic (1)
        
$
2.20
  
$
1.95
    
13
 
Per weighted average unit - diluted (2)
        
$
2.20
  
$
1.95
    
13
 
Declared distributions
       
$
283,465
  
$
230,714
    
23
 
Per Unit (1)
          
1.44
   
1.44
   
-
 
Percent of cash flow distributed
          
66
%
  
74
%
  
(12
)
(1) Excludes exchangeable shares
(2) Includes dilutive impact of unit options, exchangeable shares and convertible debentures.
  

For the year ended December 31, 2006, cash flow increased 39 percent or $121.5 million to $432.7 million from $311.2 million for 2005 (per unit in 2006 - $2.20; 2005 - $1.95). COGP generated $185.3 million, USOGP $63.0 million, and Midstream $184.4 million of cash flow during 2006. During 2005 COGP generated cash flow of $185.1 million, USOGP $59.8 million, and Midstream $66.3 million.

Canadian oil and gas operations cash flow contributed $185.3 million in 2006, virtually flat when compared with $185.1 million from 2005. The 2006 results reflect increased production from the Rainbow assets acquired on August 31, 2006, incremental production adds from the successful capital drilling programs in the core areas and higher realized crude oil and natural gas liquids prices, as well as realized gains on financial derivative instruments. These factors were offset by natural production declines, a lower realized natural gas price due to a decrease in the AECO natural gas index price, and higher general and administrative expenses when compared to 2005.

The Midstream business unit added $184.4 million to 2006 cash flow, 178 percent above the $66.3 million recorded in the year ended December 31, 2005. Midstream cash flow has benefited from the Midstream NGL Acquisition completed in December 2005. This acquisition has extended Provident’s participation in the NGL value chain. Midstream cash flow reflects an increase in fees for services, fixed margin extraction and equity margin on marketed NGLs. Midstream cash flow from marketed NGLs benefited from an increase in propane plus prices in the year ended December 31, 2006 over 2005 accompanied by a reduction in associated product costs, mostly due to reduced natural gas prices.

The U.S. oil and gas operations provided increased cash flow of $63.0 million in 2006, compared to $59.8 million in 2005, resulting from a full year of production in 2006 from the Nautilus properties, acquired in March of 2005, and higher crude oil prices, partially offset by higher production expenses and general and administrative costs.

Declared distributions in 2006 totaled $283.5 million, 66 percent of cash flow. This compares to $230.7 million of declared distributions in 2005, 74 percent of cash flow. In previous years, Provident has paid out between 74 percent and 102 percent of its annual cash flow as distributions to unitholders. Provident’s objective is to provide stable distributions to its unitholders. 

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

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


       
Distribution Amount
  
Record Date
  
    Payment Date
  
(Cdn$)
(US$)*
  
2006
            
January 23, 2006
    
February 15, 2006
  
$
0.12
  
0.10
 
February 23, 2006
    
March 15, 2006
    
0.12
 
0.10
 
March 22, 2006
    
April 13, 2006
    
0.12
 
0.10
 
April 24, 2006
    
May 15, 2006
    
0.12
 
0.11
 
May 25, 2006
    
June 15, 2006
    
0.12
 
0.11
 
June 22, 2006
    
July 14, 2006
    
0.12
 
0.11
 
July 21, 2006
    
August 15, 2006
    
0.12
 
0.11
 
August 22, 2006
    
September 15, 2006
    
0.12
 
0.11
 
September 22, 2006
    
October 13, 2006
    
0.12
 
0.11
 
October 23, 2006
    
November 15, 2006
    
0.12
 
0.10
 
November 22, 2006
    
December 15, 2006
    
0.12
 
0.10
 
December 22, 2006
    
January 15, 2007
    
0.12
 
0.10
 
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, 2006 – Distributions paid as declared
    
$
10.95
  
7.96
 
*exchange rate based on the Bank of Canada noon rate on the payment date.
                 

For Canadian tax purposes, 2006 distributions were determined to be 93.2 percent taxable and 6.8 percent tax-deferred return of capital in the hands of Canadian unitholders. The 2005 comparables were 76.5 percent and 23.5 percent, respectively. Distributions received by U.S. resident unitholders in 2006 are classified as 97.7 percent qualified dividend and 2.3 percent tax deferred return of capital. The 2005 comparables were 94.4 percent and 5.6 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.

Proposed taxation of trust distributions

The Canadian government made an unexpected announcement on October 31, 2006, stating its intention to introduce a substantial new 31.5 percent tax on income trust distributions beginning in 2011. This announcement caused a severe negative market reaction early in November. The government remains committed to this course of action in spite of compelling evidence of the very positive impact that energy trusts in particular have on the Canadian energy industry, on the economy in general, and on government tax revenues.
 
Since the original announcement, the government has also clarified the rules around the extent to which a trust is allowed to grow before 2011 without triggering immediate taxable status. A trust can double in size before 2011, and trusts can merge without penalty. This is positive, suggesting that Provident’s near term business plan and growth objectives will not be affected by the taxation announcement.
 
Provident remains active in the efforts to try to convince the government to modify its proposal or to exempt energy trusts. As well as working with government, management is also actively engaged in strategic planning to determine the best course of action for Provident under the proposed new tax regime. With diverse businesses and a history of innovation, the Trust is well positioned to identify creative solutions. While it will take time to fully examine all options, management remains committed to making Provident a premier energy income and growth investment.
 
Net income
 
Consolidated
  
Year ended December 31,
  
($ 000s, except per unit data)
      
2006
  
2005
  
% Change
  
                   
Net income
        
$
140,920
  
$
96,926
    
45
 
Per weighted average unit
– basic(1)
          
0.72
   
0.61
   
18
 
Per weighted average unit
– diluted(2)
          
0.72
   
0.61
   
18
 
(1) Based on weighted average number of trust units outstanding
  
(2) Based on weighted average number of trust units outstanding including the dilutive impact of the unit option plan, exchangeable shares and convertible debentures.
  
 
   
 Year ended December 31,
  
($ 000s)
          
2006
   
2005
   
% Change
  
                           
COGP net income
        
$
83,453
  
$
35,352
    
136
 
USOGP net income
          
2,598
   
5,422
   
(52
)
Total oil and gas net income
        
86,051
   
40,774
   
111
 
Midstream net income
          
54,869
   
56,152
   
(2
)
Consolidated net income
        
$
140,920
  
$
96,926
    
45
 
 
Net income for the year ended December 31, 2006 increased to $140.9 million compared to $96.9 million of income in the comparable 2005 period.

The COGP business segment’s net income was $83.4 million, a $48.0 million improvement over the year ended December 31, 2005 net income of $35.4 million. The increase was mainly due to a higher future income tax recovery and an increased unrealized gain on financial derivative instruments partially offset by increased depletion, depreciation, and accretion (DD&A) expense and a decrease in earnings before interest, taxes, depletion, depreciation, accretion and other non-cash items (EBITDA) driven by lower realized natural gas prices due to the decrease in the AECO natural gas index price, and lower production compared to 2005.

The Midstream unit recorded net income of $54.9 million as compared to $56.1 million in the year ended December 31, 2005. The increase reflects higher EBITDA in 2006. The Midstream business unit had EBITDA of $219.6 million in 2006 as compared to $70.7 million in 2005. This significant improvement in EBITDA is attributable to the Midstream NGL acquisition completed in December 2005. This acquisition has extended Provident’s participation in the NGL value chain through increased managed volumes. Midstream EBITDA reflects an increase in fees for services, fixed margin extraction and equity margin on marketed NGLs. The significant improvement in Midstream EBITDA is also the result of an increase in propane plus prices in 2006 over 2005 accompanied by a reduction in associated product costs, mostly due to reduced natural gas prices. Partially offsetting this increase is unrealized losses on outstanding financial derivative instruments amounting to $68.3 million in 2006 (2005 - $1.6 million). Under generally accepted accounting principles, these unrealized “mark-to-market” amounts, which relate to financial instruments with effective periods ranging over the next five years from 2007 through 2011, are required to be recognized in the financial statements of Provident, affecting current period net income (see “Commodity price risk management program”). In addition, higher DD&A of $49.1 million compared to $11.8 million in 2005, and higher interest charges of $32.1 million versus $4.9 million in 2005 are the result of a larger asset base and increased capitalization due to the Midstream NGL Acquisition.

For the year ended December 31, 2006, USOGP net income was $2.6 million as compared to $5.4 million in the year ended December 31, 2005. USOGP generated a seven percent increase in EBITDA resulting from a full year of production in 2006 from the Nautilus properties, acquired in March of 2005 as well as higher crude oil prices. In addition, unrealized gains on financial derivative instruments were $7.7 million in 2006, compared to a loss of $1.9 million in 2005. These factors were offset by higher DD&A charges and increased non-cash unit based compensation in 2006.
 
 
 
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:
 

Consolidated
               
EBITDA Reconciliation
 Year ended December 31,
($ 000s)
  
2006
 
 2005
  
% Change
  
EBITDA
  
$
 495,889  
$349,181
  
42
 
Adjusted for:
                    
Interest and non-cash expenses excluding unrealized (loss) gain on
financial derivative instruments
  
(335,079
)
  
(229,372
)
  
46
 
Unrealized (loss) gain on financial derivative instruments
    
(43,314
)
  
7,684
   
-
 
Income before taxes and non-controlling interests
  
$
117,496
  
$
127,493
   
(8
)


Reconciliation of cash flow distribution
  
Year ended December 31,  
    
   
2006
  
 2005
  
% Change
  
Cash provided by operating activities    $ 414,349     $ 257,363       61   
Change in non-cash operating working capital
    
13,693
   
51,344
   
(73
)
Site restoration expenditures
    
4,622
   
2,481
   
86
 
Cash flow from operations before changes in working capital and site restoration expenditures
   
432,664
   
311,188
   
39
 
Cash withheld for financing and investing activities
    
(149,199
)
  
(80,474
)
  
85
 
Cash distributions to unitholders
    
283,465
   
230,714
   
23
 
Accumulated cash distributions, beginning of period
    
643,360
   
412,646
   
56
 
Accumulated cash distributions, end of period
  
$
926,825
  
$
643,360
   
44
 
Cash distributions per unit
  
$
1.44
  
$
1.44
    
-
 

Cash withheld for financing and investing activities is a discretionary amount and represents the difference between cash flow from operations (before changes in working capital and site restoration expenditures) and distributions.

Taxes
 
Year ended December 31,
               
($ 000s)
  
2006
  
 2005
  
% Change
  
Capital taxes
 
$
1,314
  
$
4,780
   
(73
)
Current and withholding taxes
    
5,829
   
5,628
   
4
 
Future income tax (recovery) expense
    
(34,316
)
  
17,793
   
-
 
   
$
(27,173
)
$
28,201
   
-
 
 
For the year ended December 31, 2006, the expected income tax expense was $40.7 million on income before taxes and non-controlling interests of $117.5 million. The difference from the expected expense and the total tax recovery of $27.2 million 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 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 provision for taxes is required by the Trust. 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.

Capital taxes in the year ended December 31, 2006 totaled an expense of $1.3 million, a reduction from $4.8 million recorded in the year ended December 31, 2005. The reduction is due to the elimination of the federal large corporation tax effective January 1, 2006. This legislation was enacted on June 22, 2006.
 
The current and withholding taxes total $5.8 million in the year ended December 31, 2006, an increase of $0.2 million over the comparable 2005 period. These taxes arise from Provident’s U.S. based operations, which are subject to U.S. federal and state income taxes. Also, payments from U.S. entities to Canadian entities are subject to withholding taxes if the distributions are characterized as dividends or interest.

In 2006, future income tax recovery totaled $34.3 million compared to an expense of $17.8 million in 2005. The recovery was generated by interest and royalty charges to incorporated subsidiaries from the Trust as well as tax rate reductions enacted in the second quarter of 2006.

Interest expense
 
Consolidated
       
Year ended December 31, 
      
($ 000s, except as noted)
      
2006
  
2005
  
% Change
  
                           
Interest on bank debt
        
$
34,666
  
$
10,875
    
219
 
Weighted-average interest rate on bank debt
          
5.30
%
  
3.85
%
  
38
 
Interest on 10.5% convertible debentures(2)
          
-
   
1,682
   
(100
)
Interest on 8.75% convertible debentures
          
2,573
   
4,923
   
(48
)
Interest on 8.0% convertible debentures
          
2,500
   
3,577
   
(30
)
Interest on 6.5% convertible debentures (1)
          
6,437
   
5,393
   
19
 
Interest on 6.5% convertible debentures (3)
          
9,715
   
1,219
   
697
 
Total cash interest
       
$
55,891
  
$
27,669
    
102
 
                           
Weighted average interest rate on all long-term debt
          
5.81
%
  
4.91
%
  
18
 
Non-cash accretion expense - convertible debentures
          
2,694
   
2,849
   
(5
)
Total interest including accretion on convertible debentures
        
$
58,585
  
$
30,518
    
92
 
(1) On March 1, 2005 the Trust issued $100.0 million of unsecured subordinated convertible debentures with a 6.5 percent coupon rate maturing August 31, 2012.
(2) On May 31, 2005 the Trust redeemed the 10.5 percent unsecured subordinated convertible debentures issuing 3.5 million trust units and $3.0 million in cash.
(3) On November 15, 2005 the Trust issued $150.0 million of unsecured subordinated convertible debentures with a 6.5 percent coupon rate maturing April 30, 2011.
 
Interest on bank debt increased in 2006 compared to 2005 due to increased capitalization including debt levels that resulted from the $773 million Midstream NGL Acquisition in the fourth quarter of 2005 and the $473 million Rainbow asset acquisition in the third quarter of 2006. As well, increases in the Canadian prime rate and the U.S. LIBOR rate have resulted in higher interest rates on bank debt.
 
Cash interest expense on debentures increased in 2006 compared to 2005 reflecting the March 1, 2005 issue of $100 million of 6.5 percent subordinated convertible debentures and the November 15, 2005 issue of $150 million of 6.5 percent subordinated convertible debentures, partly offset by redemptions and conversions of subordinated convertible debentures.

Financial instruments

Commodity price risk management program

For the year ended December 31, 2006 $13.5 million was recorded as a realized loss on financial derivative instruments due to the Commodity Price Risk Management Program (the Program) with $1.9 million related to the combined oil and gas operations as a realized gain and a realized loss of $15.4 million associated with the Midstream segment.
 
In the oil and gas business units the realized loss in 2006 associated with crude oil totaled $5.7 million ($0.97 per barrel) and a realized gain of $7.6 million related to natural gas ($0.25 per gj). The combined total was a gain of $1.9 million or $0.16 per boe. In 2005 the Program recorded a realized loss of $64.6 million or $5.24 per boe with $59.0 million related to crude oil ($8.36 per barrel) and $5.6 million related to natural gas ($0.19 per gj).
 
In 2006 the Midstream segment recorded a realized loss of $15.4 million primarily on propane and ethane price stabilization and frac-spread margin hedging activities. In 2005 the Program recorded a realized loss of $2.3 million for these activities.
 
Realized gains on foreign exchange contracts which fixed the exchange rates on foreign currency contracts related to the Program have been presented as a component of foreign exchange gain and other and allocated to their respective business segments.
 
On a per trust unit basis the opportunity cost of the Program decreased to $0.07 per trust unit in 2006 from $0.42 per trust unit in 2005.
 
At December 31, 2006 the mark to market value of open contracts was in a net loss position of $52.9 million based upon commodity prices prevailing at that date. Under generally accepted accounting principles, these unrealized “mark-to-market” opportunity costs, which relate to hedging positions with effective periods ranging over the next five years from 2007 through 2011, 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 price volatility. 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 2007. The derivative instruments the Trust uses include puts, calls, costless collars, participating swaps, fixed and 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 stipulated that corporations publicly traded on U.S. financial exchanges must have assessed the effectiveness of their internal controls over financial reporting by December 31, 2006. As a foreign filer listed on the New York Stock Exchange, Provident was required to conduct the assessment.

Based on their evaluation as of December 31, 2006, 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, other than as described below, as of December 31, 2006, there were no changes in Provident’s internal controls over financial reporting that occurred during 2006 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, 2006, the company’s internal controls were found to be operating free of any material weaknesses.
 
Property Acquisitions

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 assets provide daily production of approximately 5,500 barrels of oil equivalent, over 90 percent of which is natural gas, and over 200 identified drilling locations.
 
The purchase price was $472.8 million (including acquisition costs) and was financed by the issuance of 16,325,000 units at $13.85 per unit and Provident’s credit facilities (see note 3 to consolidated financial statements).

In the fourth quarter of 2006, Provident spent $8.6 million on oil and gas property acquisitions primarily on acquiring additional working interests in Northwest Alberta ($6.7 million) and in Southern Alberta ($1.7 million).

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. In 2005, the Midstream NGL Acquisition resulted in additional goodwill of $100.4 million (as adjusted in 2006. See note 3 to the consolidated financial statements). 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
  
 
  
December 31, 
      
($ 000s)
      
2006
  
2005
  
% Change
  
 
                          
Long-term debt - revolving term credit facilities
        
$
702,993
  
$
586,597
    
20
 
Long-term debt - convertible debentures
          
285,792
   
298,007
   
(4
)
Total debt
          
988,785
   
884,604
   
12
 
 
                          
Equity (at book value)
          
1,542,974
   
1,404,826
   
10
 
Total capitalization at book value
        
$
2,531,759
  
$
2,289,430
    
11
 
 
                          
Total debt as a percentage of total book value capitalization
          
39
%
  
39
%
  
-
 

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

Long-term debt and working capital

As at December 31, 2006 Provident had drawn on 63 percent of its term credit facilities of $925 million and U.S. $158 million as compared to 68 percent drawn on its $750 million and U.S. $100 million term credit facilities as at December 31, 2005. The increase in the level of bank debt was due to the increased scale of operations primarily due to acquisitions.

At December 31, 2006 Provident had letters of credit guaranteeing Provident’s performance under certain commercial and other contracts that totaled $31.9 million, increasing bank line utilization to 66 percent. The guarantees at December 31, 2005 totaled $45.1 million.

Provident’s working capital decreased by $23.6 million from $79.4 million to $55.8 million as at December 31, 2006. Of the decrease, $24.8 million is due to a reduction in inventory and $21.8 million due to a reduction in cash and cash equivalents. These decreases in working capital are partially offset by a $14.7 million reduction in accounts payable and accrued liabilities and a $4.4 million reduction in net current financial derivative instrument liability.

 
The ratio of debt to cash flow in 2006 was 2.3 to one, compared to 2.8 to one in 2005. Fourth quarter cash flow in 2006 was $122.7 million. The ratio of debt to annualized fourth quarter cash flow was 2.0 to one, as compared to 2005 fourth quarter annualized debt to cash flow of 2.3 to one. The reduction in debt to cash flow figures is due to increased cash flows as a result of the Midstream NGL Acquisition.

Trust units and exchangeable shares
 
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, 0.9 million units were issued on conversion of exchangeable shares with a value of $9.0 million (2005 - 3.0 million units; conversion amount $28.4 million). For the year ended December 31, 2006 the Trust issued 1.3 million units on conversion of convertible debentures (2005 - 9.6 million units). An additional 0.9 million units pursuant to the unit option plan were issued for the year ended December 31, 2006 (2005 - 2.3 million units). Under Provident’s Premium Distribution, Distribution Reinvestment (DRIP) and Optional Unit Purchase Plan program 3.0 million units were elected in 2006 and were issued or are to be issued representing proceeds of $36.9 million (2005 - 1.4 million units for proceeds of $18.4 million).

At December 31, 2006 management and directors held approximately 1.0 percent of the outstanding units and exchangeable shares.

Non-Controlling Interest
 
 
(i)
USOGP operations

     
 Year ended December 31,  
  
Non-controlling interest USOGP ($ 000s)
      
2006
  
 2005
 
Non-controlling interest, beginning of year
        
$
11,885
  
$
13,649
 
Net income attributable to non-controlling interest
          
2,995
   
1,596
 
Distributions to non-controlling interest holders
          
(6,523
)
  
(3,360
)
Investments by non-controlling interest
          
72,754
   
-
 
Non-controlling interest, end of year
          
81,111
   
11,885
 
Accumulated income attributable to non-controlling interest
    
$
5,514
  
$
2,519
 
 
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, 2006 to approximately 4.4 percent (2005 - 4.4 percent). Contributions by this non-controlling interest total $0.5 million in 2006 (2005 - nil).

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 $3.7 million in 2006.

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, including an underwriter’s option, of 6,900,000 common units at U.S. $18.50 per unit, resulted in approximately 34 percent of the MLP held by partners not controlled by Provident. Contributions by this non-controlling interest total $131.6 million in 2006. Non-controlling interest was increased by $68.5 million as a result of this transaction. The difference of $63.1 million has been recorded against property, plant and equipment in accordance with full cost accounting principles.
 
 
(ii)
Exchangeable shares

Following is a summary of the non-controlling interest - exchangeable shares for the years ended December 31, 2006 and 2005:

Non-controlling interest - Exchangeable shares ($ 000s)
  
2006
  
2005
  
Non-controlling interest, beginning of year
  
$
8,259
  
$
35,921
  
Reduction of book value for conversion to trust units
    
(9,013
)
  
(28,432
)
Net income attributable to non-controlling interest
    
754
   
770
 
Non-controlling interest, end of year
  
$
-
  
$
8,259
  
Accumulated income attributable to non-controlling interest
  
$
-
  
$
2,252
  
 
In 2006, all outstanding exchangeable shares were converted into Provident trust units.

Capital expenditures and funding


Consolidated
  
Year ended December 31,
    
($ 000s)
  
2006
  
2005
 
% Change
  
Capital Expenditures and Funding
                    
                     
Capital Expenditures
                    
Capital expenditures and reclamation fund contributions
  
$
(193,183
)
$
(159,398
)
  
21
 
Property acquisitions
    
(480,357
)
  
(586
)
  
81,872
 
Corporate acquisitions
    
(1,036
)
  
(863,723
)
  
(100
)
Property dispositions
    
(1,268
)
  
45,100
   
-
 
Net capital expenditures
  
$
(675,844
)
$
(978,607
)
  
(31
)
                     
Funded By
                    
Cash flow net of declared distributions to unitholders and non-controlling interest
  
$
142,676
  
$
77,114
    
85
 
Increase in long-term debt
    
117,385
   
325,771
   
(64
)
Issue of convertible debentures, net of issue costs
    
-
   
239,822
   
(100
)
Redemption of convertible debentures
    
-
   
(2,997
)
  
(100
)
Issue of trust units, net of issue costs; excluding DRIP
    
220,225
   
377,362
   
(42
)
DRIP proceeds
    
36,851
   
18,443
   
100
 
Contributions by non-controlling interests
    
135,829
   
-
   
-
 
Change in working capital, including cash, payment of financial
derivative instruments and sale of assets
    
22,878
   
(56,908
)
  
-
 
Net capital expenditure funding
  
$
675,844
  
$
978,607
    
(31
)

Capital expenditures were funded by a combination of cash flow, debt and equity issued from treasury through public offerings, the DRIP program and contributions by non-controlling interest. Provident’s strategy is to fund acquisitions by accessing the capital markets and to fund capital expenditures through cash flow, DRIP and other equity if needed.

Net asset value
 
Provident’s net asset value (“NAV”) as at December 31, 2006, is summarized in the table below. The net asset value is calculated on a diluted basis, which includes exchangeable shares and unit options, and is presented at eight percent and 10 percent discounted cash flow cases. The pricing used at both December 31, 2006 and December 31, 2005 is derived from a report prepared by McDaniel & Associates Consultants Ltd., independent engineers.


($ 000s except per unit data)
  
PV 8%
  
PV 10%
  
Net Asset Value:
              
Present value of proved plus probable oil and natural gas reserves (1) (2)
$
1,933,338
  
$
1,726,538
  
Midstream assets (3)
    
1,737,905
   
1,493,039
 
Add:
          
Working Capital
    
65,500
   
65,500
 
Land (4) (5)
    
48,923
   
48,923
 
Proceeds from Options
    
20,283
   
20,283
 
Cash Reserved for Future Reclamation
    
-
   
-
 
Investments
    
4,320
   
4,320
 
Less:
          
Financial Hedging Losses (2)
    
27,769
   
26,290
 
Long Term Debt
   
(988,785
)
  
(988,785
)
Other long-term liabilities
    
(16,305
)
  
(16,305
)
Non-controlling interest - USOGP operations
    
(81,111
)
  
(81,111
)
Consolidated Provident Net Asset Value
  
$
2,751,837
  
$
2,298,692
  
Consolidated Provident Net Asset Value per Unit
  
$
12.90
  
$
10.77
  
2005 comparatives
              
Consolidated Provident Net Asset Value per Unit
  
$
13.04
  
$
11.15
  
(1) Evaluated by McDaniel and NSA.
    
(2) Pricing is based on McDaniel pricing effective December 31, 2006.
    
(3) The Midstream assets represent discounted estimated cash flow streams (EBITDA less maintenance capital) for 25 years.
(4) Canadian land holdings evaluated by Seaton Jordan & Associates Ltd. effective December 31, 2006.
 
Non-cash unit based compensation
 
Non-cash unit based compensation include expenses or recoveries associated with Provident’s unit option plan, restricted and performance unit plan, unit appreciation rights and other unit based compensation plans. Provident accounts for the unit option plan using the fair value of the option, at the time of issue. The other unit based compensation is recorded at the estimated fair value of the notional units granted. Compensation expense associated with the plans is deferred and recognized in earnings over the vesting periods of each plan. Provident recorded a non-cash expense of $23.1 million for the year ended December 31, 2006 (2005 - $9.8 million) included in general and administrative expense. At December 31, 2006, the current portion of the liability totaled $18.2 million and the long-term portion totaled $16.3 million.

Outlook

With a $170 million capital budget, Provident is expecting another active year in 2007. Weakening commodity prices early in the year impacted cash flow, although management is taking advantage of the stronger forward commodity prices to add some additional hedging to protect a floor level of EBITDA in each of the business units.

In the Canadian Oil and Gas Production business (COGP), Provident intends to spend $72 million across its six operating areas in 2007. Over half of that capital will be deployed on the recently-acquired assets in Northwest Alberta and the organic shallow gas play in Southwest Saskatchewan. The planned divestiture of heavy oil assets in Lloydminster that was mentioned in the third quarter press release did not take place. Provident did not receive bids of sufficient value to warrant a transaction, reflecting the uncertainty in the marketplace late in the year caused by the government taxation announcement.

Provident expects COGP production to average 22,000 to 24,000 boed in 2007. Operating costs should stay reasonably consistent with 2006 levels. In 2007, COGP will continue to focus on strengthening internal operating capability, and specifically on applying the shallow gas knowledge gained in Southwest Saskatchewan to the new natural gas assets in Northwest Alberta.

In the U.S. Oil and Gas Production business (USOGP), Provident plans to spend $53 million in 2007, a significant portion of which will be used for Orcutt and other growth opportunities. The MLP will continue to pursue acquisition opportunities that fit its successful business model, such as the Permian Basin acquisition that was completed early in 2007. Production is expected to average 8,000 to 8,500 boed in 2007, which includes both the
 
MLP and the pre-existing business. These numbers assume initial production from the Orcutt diatomite project late in 2007. Operating costs are expected to stay fairly consistent with 2006 levels, as weaker commodity prices have not yet translated into lower costs in that business.

In the Midstream business, Provident plans to spend $42 million in capital expenditures in 2007, of which only $6 million is required for sustaining capital. The remainder is planned for growth projects including further expansion of the condensate rail offloading terminal and new storage caverns at Redwater.

2007 Midstream EBITDA will depend on the business environment. Thus far in the first quarter, frac spreads have weakened from their 2006 highs, and lower commodity prices have reduced product margins in absolute terms. However, propane demand has been strong in Eastern North America, effectively drawing down Provident’s substantial winter propane inventories.

The remaining $3 million in capital is intended for corporate purposes. In addition, the Trust will incur one-time net expenditures of approximately $23 million in 2007 and 2008 related to a move of the Calgary head office into a new building. These expenditures will be amortized over the 14 year term of the lease. As a result of Provident’s growth, employees are currently housed in two buildings, both of which are full to capacity. The planned 2008 move into Livingston Place, an office complex currently under construction, will accommodate growth and improve efficiency by consolidating all employees into a single location.

With respect to corporate priorities for 2007, Provident management will continue to develop strategy in response to the government taxation announcement in 2007, as well as evaluate acquisition opportunities that may arise as the energy trust sector adjusts to the planned tax changes. As always, Provident’s primary focus is on delivering long-term value and sustainability for unitholders. In 2006, the Trust delivered a total return for investors of 13.8 percent, which was among the very best of the energy trusts in a challenging year.
 
COGP segment review
 
Crude oil and liquids price

COGP
    
Year ended December 31,
 		      
($ per bbl)
    
2006
  
2005
  
% Change
  
Oil per barrel
                       
WTI (US$)
      
$
66.22
  
$
56.56
    
17
 
Exchange rate (from US$ to Cdn$)
        
1.13
   
1.21
   
(7
)
WTI expressed in Cdn$
      
$
74.83
  
$
68.44
    
9
 
                         
Realized pricing before financial derivative instruments
                        
Light/Medium oil
     
$
57.18
  
$
52.02
    
10
 
Heavy oil
     
$
36.80
  
$
31.33
    
17
 
Natural gas liquids
      
$
51.91
  
$
49.15
    
6
 
Crude oil and natural gas liquids
     
$
52.38
  
$
45.25
    
16
 
 

The above prices are net of transportation expense.

For the year ended December 31, 2006 COGP’s realized crude oil and natural gas liquids price, prior to the impact of financial derivative instruments, increased by 16 percent to average $52.38 compared to $45.25 in 2005. The 2006 increase related to a 17 percent higher US$ 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)
    
2006
  
2005
  
% Change
  
                         
AECO monthly index (Cdn$ per mcf)
      
$
6.98
  
$
8.49
    
(18
)
Corporate natural gas price per mcf
before financial derivative instruments
      
$
6.66
  
$
8.42
    
(21
)
 
The above prices are net of transportation expense.

For the year ended December 31, 2006 COGP’s realized natural gas price, excluding financial derivative instruments, decreased 21 percent as compared to 2005, comparable to the decrease in the benchmark AECO monthly index price. Provident markets approximately 17 percent of its natural gas to aggregators and mainly sells to the market on daily indices, receiving prices that are based on the heat content of the natural gas. Provident’s realized prices and changes in prices can therefore differ from benchmark indices.

Production

   
Year ended December 31,
    
COGP
              
   
2006
  
2005
  
% Change
  
Daily production
                    
Crude oil - Light/Medium (bpd)
    
6,815
   
8,058
   
(15
)
- Heavy (bpd)
    
2,057
   
4,358
   
(53
)
Natural gas liquids (bpd)
    
1,401
   
1,572
   
(11
)
Natural gas (mcfd)
    
82,469
   
74,936
   
10
 
Oil equivalent (boed) (1)
    
24,018
   
26,477
   
(9
)
(1) Provident reports equivalent production converting natural gas to oil on a 6:1 basis.
                    
 
For the year ended December 31, 2006, COGP production averaged 24,018 boed, a nine percent decrease compared to 26,477 boed in 2005. The additional production from the Rainbow assets acquired on August 31, 2006 and the production volumes added through drilling and optimization activities were more than offset by the disposition of 2,100 boed of production in September 2005 and natural production declines.

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

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

COGP
                                  
Year ended December 31, 2006
  
West Central Alberta
  
Southern
Alberta
  
Northwest
Alberta
  
Southeast Saskatchewan
  
Southwest Saskatchewan
  
Lloydminster
  
Other
  
Total
  
                                   
Daily production
                                                  
Crude oil - Light/Medium (bpd)
    
1,109
   
2,244
   
58
   
1,704
   
321
   
1,322
   
57
   
6,815
 
- Heavy (bpd)
    
-
   
-
   
-
   
-
   
-
   
2,057
   
-
   
2,057
 
Natural gas liquids (bpd)
    
1,227
   
127
   
24
   
-
   
-
   
22
   
1
   
1,401
 
Natural gas (mcfd)
    
34,989
   
23,195
   
8,778
   
164
   
13,820
   
1,324
   
199
   
82,469
 
Oil equivalent (boed) (1)
    
8,168
   
6,237
   
1,545
   
1,731
   
2,624
   
3,622
   
91
   
24,018
 


COGP
                                  
Year ended December 31, 2005
  
West Central Alberta
 
Southern
Alberta
 
Northwest
Alberta
  
Southeast Saskatchewan
 
Southwest Saskatchewan
  
Lloydminster
 
Other
  
Total
  
                                   
Daily production
                                                  
Crude oil - Light/Medium (bpd)
    
1,300
   
2,722
   
-
   
1,714
   
845
   
1,470
   
7
   
8,058
 
- Heavy (bpd)
    
-
   
-
   
-
   
-
   
-
   
4,358
   
-
   
4,358
 
Natural gas liquids (bpd)
    
1,406
   
149
   
-
   
-
   
1
   
16
   
-
   
1,572
 
Natural gas (mcfd)
    
40,198
   
26,345
   
-
   
202
   
6,260
   
1,909
   
22
   
74,936
 
Oil equivalent (boed) (1)
    
9,406
   
7,262
   
-
   
1,747
   
1,889
   
6,162
   
11
   
26,477
 
(1) Provident reports equivalent production converting natural gas to oil on a 6:1 basis.
 
Internal development activities included 59.0 net wells drilled for the year ended December 31, 2006 with a 98 percent success rate. Provident’s most active areas, southeast and southwest Saskatchewan realized 31.5 net wells drilled. The focus of southern Saskatchewan is a shallow gas drilling program that will realize production and reserve additions for several years. Provident’s other core areas remain active with additional activity in southern Alberta where Provident is actively drilling shallow gas wells resulting in 14.3 net wells drilled and in Lloydminster
 
where Provident is drilling low risk heavy oil wells. In West Central Alberta, Provident continues its strategy of farming out high risk exploration land to generate cash flow with minimal or no capital outlay. COGP’s new area, Northwest Alberta, drilled 5.4 net wells in 2006 as it began the winter drilling program, which was ahead of its planned 2007 drilling schedule due to favourable weather conditions and advanced planning. Additions to proved plus probable reserves before revisions through internal capital replaced approximately 42 percent of annual production.

Revenue and royalties

COGP
                  
     
 Year ended December 31,
    
($ 000s except per boe and mcf data)
     
2006
  
2005
  
% Change
  
                           
Oil
                         
Revenue
        
$
169,852
  
$
202,845
    
(16
)
Realized loss on financial derivative instruments
          
(3,193
)
  
(42,700
)
  
(93
)
Royalties (net of ARTC)
          
(32,567
)
  
(40,067
)
  
(19
)
Net revenue
        
$
134,092
  
$
120,078
    
12
 
Net revenue (per barrel)
        
$
41.41
  
$
26.50
    
56
 
Royalties as a percentage of revenue
          
19.2
%
  
19.8
%
       
                           
Natural gas
                         
Revenue
        
$
200,584
  
$
230,195
    
(13
)
Realized gain (loss) on financial derivative instruments
          
7,564
   
(5,608
)
  
-
 
Royalties (net of ARTC)
          
(42,200
)
  
(48,484
)
  
(13
)
Net revenue
        
$
165,948
  
$
176,103
    
(6
)
                           
Net revenue (per mcf)
        
$
5.51
  
$
6.44
    
(14
)
Royalties as a percentage of revenue
          
21.0
%
  
21.1
%
        
                           
Natural gas liquids
                         
Revenue
        
$
26,545
  
$
28,203
    
(6
)
Royalties
          
(6,458
)
  
(6,852
)
  
(6
)
Net revenue
        
$
20,087
  
$
21,351
    
(6
)
Net revenue (per barrel)
        
$
39.28
  
$
37.21
    
6
 
Royalties as a percentage of revenue
          
24.3
%
  
24.3
%
       
                           
Total
                         
Revenue
        
$
396,981
  
$
461,243
    
(14
)
Realized gain (loss) on financial derivative instruments
          
4,371
   
(48,308
)
  
-
 
Royalties (net of ARTC)
          
(81,225
)
  
(95,403
)
  
(15
)
Net revenue
       
$
320,127
  
$
317,532
    
1
 
Net revenue (per boe)
        
$
36.52
  
$
32.86
    
11
 
Royalties as a percentage of revenue
          
20.5
%
  
20.7
%
         
Note: the above revenue, net revenue and net revenue per boe figures are presented net of transportation expenses.
 
For the year ended December 31, 2006 COGP production revenue was $397.0 million, a decrease of 14 percent from $461.2 million in 2005. The decrease in revenue is a result of lower realized natural gas price and lower crude oil and natural gas liquids production partially offset by higher realized crude oil and natural gas liquids prices and the additional natural gas production from the Rainbow assets acquired on August 31, 2006. Royalties as a percentage of revenue have remained relatively constant at approximately 20.5 percent compared to the prior year. The preceding factors, as well as the $4.4 million realized gain on financial derivative instruments compared to a $48.3 million loss in 2005, account for net revenue of $320.1 million in 2006, one percent higher than the $317.5 million recorded in 2005.
 
Net revenue per boe in 2006 increased 11 percent to $36.52 from $32.86 in 2005 resulting primarily from a higher realized gain on financial derivative instruments and a reduction of lower priced heavy oil volumes to nine percent of total production in 2006 compared to 16 percent in 2005 and increases in realized crude oil and natural gas liquids prices. These price increases were more than offset by lower realized natural gas prices as described above combined with the increased proportion of natural gas production to 57 percent of total production in 2006 compared to 47 percent in 2005.

Production expenses

COGP
     
 Year ended December 31,
    
($ 000s, except per boe data)
        
2006
  
2005
  
% Change
  
                           
Production expenses
        
$
97,626
  
$
95,278
    
2
 
Production expenses (per boe)
        
$
11.14
  
$
9.86
    
13
 

For the year ended December 31, 2006 production expenses increased two percent to $97.6 million from $95.3 million and increased by 13 percent to $11.14 per boe from $9.86 per boe in the prior year. Throughout 2006, operating expenses continued to increase in a number of categories including well servicing, maintenance, fluid hauling, and power and fuel and combined with lower production volumes resulted in higher operating costs on a per boe basis. Cost increases included higher than expected costs for electricity and adjustments related to prior periods operating costs by operators on non-operated properties. 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)
        
2006
  
2005
  
% Change
  
Netback per boe
                          
Gross production revenue
        
$
45.29
  
$
47.73
    
(5
)
Royalties (net of ARTC)
          
(9.27
)
  
(9.87
)
  
(6
)
Operating costs
          
(11.14
)
  
(9.86
)
  
13
 
Field operating netback
          
24.88
   
28.00
   
(11
)
Realized gain (loss) on financial derivative instruments
  
0.50
   
(5.00
)
  
-
 
Operating netback after realized financial derivative instruments
$
25.38
  
$
23.00
    
10
 
 
COGP operating netbacks have transportation expense netted against gross production revenue.

The 2006 field operating netback of $24.88 per boe was 11 percent below the $28.00 per boe for the prior year. This reflects COGP’s lower realized natural gas prices due to the decrease in benchmark AECO monthly index price combined with the increased proportion of natural gas production to 57 percent of total production from 47 percent in 2005. This was partially offset by increased realized crude oil and natural gas liquids prices and a decrease in COGP’s production mix of low netback heavy oil to nine percent in 2006 from 16 percent in 2005. Royalties, which are price sensitive, decreased by six percent on a boe basis reflecting lower prices, prior to the impact of financial derivative instruments. The 2006 operating netbacks after financial derivative instruments increased by 10 percent to $25.38 from $23.00 in the prior year due to the preceding factors as well as a realized gain on financial derivative instruments of $0.50 per boe compared to losses of $5.00 per boe in the prior year.

General and administrative

COGP
  
 Year ended December 31,
    
                   
($ 000s, except per boe data)
      
2006
  
2005
  
% Change
  
                           
Cash general and administrative
        
$
24,065
  
$
18,552
    
30
 
Non-cash unit based compensation
          
4,320
   
2,640
    
64
 
         
$
28,385
  
$
21,192
    
34
 
Cash general and administrative (per boe)
        
$
2.75
  
$
1.92
    
43
 
 
In 2006 COGP cash general and administrative expenses increased 30 percent to $24.1 million compared to $18.6 million in 2005. On a boe basis, cash general and administrative expenses increased 43 percent to $2.75 per boe in
 
2006 compared to the $1.92 per boe in the prior year. The increase in cash general and administrative expenses reflects additional costs associated with a more competitive landscape affecting the cost of hiring and compensating employees and consultants as well as increases in rent, insurance and compliance and reporting costs, including costs related to the implementation of procedures and documentation in connection with the U.S. Sarbanes-Oxley Act.

COGP operations are capable of absorbing additional production, particularly in existing core areas, with little impact on cash general and administrative expenses.

Non-cash unit based compensation increased 64 percent to $4.3 million in 2006 from $2.6 million in 2005. The increase reflects a more competitive landscape affecting the cost of hiring and compensating employees and increased incentives due to performance of the Trust on specific performance indicators.

Capital expenditures

COGP
   
 Year ended December 31,
               
($ 000s)
      
2006
  
2005
  
                     
Capital expenditures - by area
                    
West central Alberta
        
$
11,280
  
$
10,514
  
Southern Alberta
          
17,619
   
21,513
 
Northwest Alberta
          
4,883
   
-
 
Southeast Saskatchewan
          
1,941
   
3,147
 
Southwest Saskatchewan
          
25,677
   
38,496
 
Lloydminster
          
7,262
   
9,865
 
Office and other
          
1,426
   
1,867
 
Total additions
        
$
70,088
  
$
85,402
  
                     
Capital expenditures - by category
                    
Geological, geophysical and land
        
$
4,508
  
$
8,473
  
Drilling, recompletions, and workovers
          
56,807
   
41,315
 
Facilities and equipment
          
6,353
   
33,626
 
Other capital
          
2,420
   
1,988
 
Total additions
        
$
70,088
  
$
85,402
  
                     
Property acquisitions
        
$
482,369
  
$
586
  
Property dispositions
        
$
(1,264
)
$
45,100
  
 
In 2006, Provident’s COGP segment spent $27.6 million in the Southeast and Southwest Saskatchewan core areas on acquiring mineral rights for future development ($3.2 million), drilling for shallow gas and recompletions ($21.5 million), and facility work ($2.9 million). In Southern Alberta $17.6 million was spent on drilling activities and recompletions ($15.5 million), facility upgrades ($0.9 million) and seismic and mineral rights acquisitions ($1.1 million). In West central Alberta $11.3 million was spent largely on non-operated drilling ($8.5 million) and facility work ($2.2 million). COGP’s new area, Northwest Alberta, spent $4.9 million primarily on drilling activities and preparation for the winter drilling program which was ahead of its planned winter drilling schedule at year end. Provident spent $7.3 million in the Lloydminster area primarily on drilling and recompletion activities ($6.9 million) and facility work ($0.3 million). Office and other items accounted for $1.4 million of capital.

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 assets are expected to provide daily production of approximately 5,500 barrels of oil equivalent, over 90 percent of which is natural gas, and over 200 identified drilling locations.
 
The purchase price was $472.8 million (including acquisition costs) and was financed by the issuance of 16,325,000 units at $13.85 per unit and Provident’s credit facilities (see note 3 to consolidated financial statements).

In the fourth quarter of 2006, COGP also spent $8.6 million on property acquisitions primarily on acquiring additional working interests in Northwest Alberta ($6.7 million) and in Southern Alberta ($1.7 million).
 
In 2005 asset dispositions of non-core assets totaled $45.1 million, primarily consisting of the September 29, 2005 non-core properties disposition of $44.6 million. COGP will continue to seek opportunities to dispose of its non-core properties given the competitive property market.

Depletion, depreciation and accretion (DD&A)

COGP
  
 Year ended December 31,
    
                   
($ 000s, except per boe data)
      
2006
  
2005
  
% Change
  
                           
DD&A
        
$
168,953
  
$
155,929
    
8
  
DD&A per boe
        
$
19.27
  
$
16.13
    
19
  

The COGP DD&A rate of $19.27 per boe increased 19 percent for 2006 compared to $16.13 per boe in 2005. The increase was primarily as a result of the Rainbow asset acquisition. Additions to property, plant and equipment of $660.4 million for the acquisition include $185.7 million due to the recording of future income taxes. This, combined with higher net per boe reserve acquisition costs, resulted in increased per boe DD&A. The cost of acquiring or drilling proved reserves in western Canada in an environment with higher commodity prices and increased drilling costs will be reflected in the DD&A rate going forward.

In 2006 DD&A also includes accretion expense associated with asset retirement obligation of $1.9 million (2005 - $2.5 million).

As part of the reconciliation of Provident’s financial statements to United States generally accepted accounting principles (U.S. GAAP), disclosed in note 18 to consolidated financial statements, the Trust has reflected additional depletion in 2006 of $382.2 million (2005 - nil) and a related future income tax recovery of $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 principles.
 
USOGP segment review

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

In the fourth quarter of 2006, Provident, through its USOGP subsidiaries, completed its initial public offering (“IPO”) of 6.9 million units at U.S. $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. Selected producing assets in the Los Angeles basin in California and in Wyoming were transferred to the MLP. The MLP operates approximately two-thirds of existing USOGP production and approximately one-half of USOGP reserves. The previously existing subsidiary (“BreitBurn”) continues to operate some Los Angeles basin assets at West Pico and the Orcutt field (which is the site of the steam-assisted diatomite pilot project). At December 31, 2006 the Trust indirectly owns approximately 66 percent of the MLP and 96 percent of BreitBurn. The MLP and BreitBurn continue to be managed by the management team which operated the USOGP business unit prior to the IPO. The USOGP segment includes the consolidated results of the MLP and BreitBurn. Non-controlling interests include the public ownership in the MLP, 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 the second quarter of 2006.
 
Crude oil, natural gas liquids and natural gas pricing

                   
USOGP
      
Year ended December 31, 
    
($ per bbl, except as noted)
      
2006
  
2005
  
% Change
  
                           
Oil per barrel
                          
WTI (US$)
        
$
66.22
  
$
56.56
    
17
 
Exchange rate (from US$ to Cdn$)
        
1.13
   
1.21
    
(7
)
WTI expressed in Cdn$
        
$
74.83
  
$
68.44
    
9
 
                           
Realized pricing before financial derivative instruments
                  
Light/Medium oil (Cdn$)
        
$
63.25
  
$
57.80
    
9
 
Natural gas liquids (Cdn$)
        
$
57.07
  
$
45.12
    
26
 
Natural gas (Cdn$ per mcf)
        
$
6.58
  
$
9.01
    
(27
)
Crude oil and natural gas liquids (Cdn$)
        
$
63.24
  
$
57.76
    
9
 

The increase in crude oil realized pricing reflects higher market prices in 2006, compared to 2005. Production from California properties is generally light, sweet crude that attracts smaller differentials to benchmark prices relative to heavier blends. Production from Wyoming properties primarily acquired through the acquisition of Nautilus on March 2, 2005 is heavier and attracts wider differentials. Production from California properties also receives better prices than Canadian or Wyoming production because of the proximity to refineries and ultimate market. Production from California properties for the year ended December 31, 2006 represented approximately 70 percent of total production while production from Wyoming properties represented approximately 30 percent of total production.

Production

   
 Year ended December 31,
    
USOGP
      
2006
  
2005
  
% Change
  
                           
Daily production - by product
                          
Crude oil - Light/Medium (bpd)
          
7,299
   
6,921
    
5
 
Natural gas liquids (bpd)
          
18
   
24
    
(25
)
Natural gas (mcfd)
          
2,422
   
2,159
    
12
 
Oil equivalent (boed) (1)
          
7,721
   
7,305
    
6
 
(1) Provident reports equivalent production converting natural gas to oil on a 6:1 basis.

 
     
Year ended December 31, 
    
USOGP
      
2006
  
2005
  
% Change
  
                           
Daily Production - by area (boed) (1)
                          
Los Angeles
          
3,901
   
3,949
   
(1
)
Santa Maria - Orcutt
          
1,491
   
1,393
   
7
 
Wyoming
          
2,329
   
1,963
   
19
 
           
7,721
   
7,305
   
6
 
(1) Provident reports equivalent production converting natural gas to oil on a 6:1 basis.
                

Production for the year ended December 31, 2006 was 7,721 boed or six percent higher than the year ended December 31, 2005. The increase is primarily attributable to a full year of production from the Wyoming properties acquired in the Nautilus acquisition on March 2, 2005. In total, the Wyoming properties acquired on March 2, 2005 added 2,254 boed to production in the year ended December 31, 2006 (2005 - 1,888 boed). In 2005, the acquired properties added 2,260 boed for the period from acquisition on March 2 to December 31, 2005.

Revenue and royalties
 
The following table outlines USOGP revenue and royalties by product line. The table excludes revenues earned from operating certain properties ($1.0 million in 2006 and 2005) on behalf of third parties.

USOGP
  
 Year Ended December 31,
    
                   
($ 000s, except per boe and mcf amounts)
  
 
  
2006
  
2005
  
% Change
  
                           
Oil
                         
Revenue
        
$
168,954
  
$
146,306
    
15
 
Realized loss on financial derivative instruments
          
(2,505
)
  
(16,323
)
  
(85
)
Royalties
         
(16,546
)
  
(14,022
)
  
18
 
Net revenue
        
$
149,903
  
$
115,961
    
29
 
Net revenue (per bbl)
        
$
56.27
  
$
45.90
    
23
 
Royalties as a percentage of revenue
          
9.8
%
  
9.6
%
      
                           
Natural gas
                         
Revenue
        
$
5,820
  
$
7,101
    
(18
)
Royalties
          
(761
)
  
(988
)
  
(23
)
Net revenue
        
$
5,059
  
$
6,113
    
(17
)
Net revenue (per mcf)
        
$
5.72
  
$
7.76
    
(26
)
Royalties as a percentage of revenue
          
13.1
%
  
13.9
%
      
                           
Natural gas liquids
                         
Revenue
        
$
368
  
$
395
    
(7
)
Royalties
          
(8
)
  
(9
)
  
(11
)
Net revenue
        
$
360
  
$
386
    
(7
)
Net revenue (per bbl)
        
$
54.79
  
$
44.05
    
24
 
Royalties as a percentage of revenue
          
2.2
%
  
2.4
%
      
                           
Total
                         
Revenue
        
$
175,142
  
$
153,802
    
14
 
Realized loss on financial derivative instruments
          
(2,505
)
  
(16,323
)
  
(85
)
Royalties
         
(17,315
)
  
(15,019
)
  
15
 
Net revenue
       
$
155,322
  
$
122,460
    
27
 
Net revenue (per boe)
        
$
55.12
  
$
45.93
    
20
 
Royalties as a percentage of revenue
          
9.9
%
  
9.8
%
      

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

Revenue for the year ended December 31, 2006 was $175.1 million or 14 percent higher than the year ended December 31, 2005. The increase is attributable to the acquisition of the Wyoming properties on March 2, 2005 combined with increased crude oil prices. Net revenue was $155.3 million or 27 percent higher than the $122.5 million of net revenue in 2005. A full year of production in 2006 from the Wyoming properties combined with increased crude oil prices and lower realized losses on financial derivative instruments all contribute to the increase. Royalties as a percentage of revenue for the year ended December 31, 2006 were consistent with royalty rates for the year ended December 31, 2005.

Production expenses

   
 Year ended December 31,
    
USOGP
                  
($ 000s, except per boe amounts)
      
2006
  
2005
  
% Change
  
Production expenses
        
$
52,008
  
$
39,513
    
32
 
Production expenses (per boe)
        
$
18.45
  
$
14.82
    
24
 

Production expenses increased 32 percent to $52.0 million in 2006 compared to $39.5 million in 2005. Production expenses per boe have increased 24 percent to $18.45 in 2006 from $14.82 in 2005. 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.
 
Operating netback

                 
USOGP
    
 Year ended December 31,
    
($ per boe)
      
2006
  
2005 
  
% Change
  
USOGP oil equivalent netback per boe
                          
Gross production revenue
        
$
62.15
  
$
57.68
    
8
 
Royalties
         
(6.14
)
  
(5.63
)
  
9
 
Operating costs
          
(18.45
)
  
(14.82
)
  
24
 
Field operating netback
        
$
37.56
  
$
37.23
    
1
 
Realized loss on financial derivative instruments
  
(0.89
)
  
(6.12
)
  
(85
)
Operating netback after realized financial derivative instruments
$
36.67
  
$
31.11
    
18
 
USOGP operating netbacks remained strong throughout 2006 due to high commodity prices and lower realized losses on financial derivative instruments when compared to 2005 partially offset by increased production costs.

General and administrative

   
   Year ended December 31,
    
USOGP
                   
($ 000s, except per boe amounts)
          
2006
    
2005
    
% Change
  
                           
Cash general and administrative
        
$
26,519
  
$
11,490
    
131
 
Non-cash unit based compensation
          
12,476
   
6,098
    
105
 
         
$
38,995
  
$
17,588
    
122
 
Cash general and administrative (per boe)
        
$
9.41
  
$
4.31
    
118
 
 
Cash general and administrative expenses were $26.5 million or $9.41 per boe in 2006, compared to $11.5 million, or $4.31 per boe in 2005. Cash general and administrative expense in 2006 includes $5.0 million payments of incentive plans, representing $1.75 per boe compared to $2.3 million in 2005 or $0.85 per boe. Also included in cash general and administrative expense in 2006 is $1.5 million (2005 - nil) of due diligence expenditures relating to a real estate development project representing $0.53 per boe (2005 - nil). The remaining increase is costs associated with compliance (including costs associated with the implementation of procedures and documentation to be in compliance with U.S. Sarbanes-Oxley Act) and increased staffing levels, as well as legal and consulting costs in connection with the initial public offering of the MLP.

Non-cash unit based compensation increased 105 percent to $12.5 million from $6.1 million in 2005. This increase in incentive plan costs is primarily driven by the initial public offering of the MLP, completed in the fourth quarter of 2006.
 
 
Capital expenditures

USOGP
              
       
 Year ended December 31,
($ 000s)
        
2006
  
2005
  
                     
Capital expenditures - by category
                    
Geological, geophysical and land
        
$
104
  
$
4,608
  
Drilling, recompletions, and workovers
          
30,943
   
29,470
 
Facilities and equipment
          
18,486
   
18,035
 
Other capital
          
4,804
   
784
 
Total additions
        
$
54,337
  
$
52,897
  
                     
Capital expenditures - by area
                    
Los Angeles
          
17,886
   
33,848
 
Santa Maria - Orcutt
          
16,579
   
8,528
 
Wyoming
          
15,023
   
5,183
 
Other capital
          
4,849
   
5,338
 
           
54,337
   
52,897
 
                     
Property acquisitions
        
$
(2,012
)
$
-
  
Property dispositions
        
$
(4
)
$
-
  
 
USOGP capital expenditures for the year ended December 31, 2006 totaled $52.3 million including the second quarter adjustment of $2.0 million to reduce accrued acquisition transaction costs related to past acquisitions. Of this total $29.6 million related to drilling, optimization and facility upgrades at West Pico, Santa Fe Springs and Orcutt. $15.0 million was directed at optimization projects in Wyoming, $3.4 million was directed to a land development project initiated in the second quarter and $6.3 million was directed at optimization projects at smaller fields as well as office equipment.

Depletion, depreciation and accretion (DD&A)

     
 Year ended December 31,
    
USOGP
                  
($ 000s, except per boe amounts)
      
2006
  
2005
 
% Change
  
                           
DD&A
        
$
31,058
  
$
25,553
    
22
 
DD&A per boe
        
$
11.02
  
$
9.58
    
15
 

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 is up $1.44 or 15 percent from 2005. This is primarily associated with a year end depletion rate adjustment reflecting 2006 capital expenditures as well as changes in reserves.

Recent developments

On January 23, 2007, the MLP completed a purchase of certain oil and gas properties in the Permian Basin of Texas, including related property and equipment, for approximately U.S. $29.0 million. The acquisition was financed through borrowings under the MLP's existing revolving credit facility.
 
 
Midstream services and marketing business segment review
 
Midstream NGL acquisition

The $773 million Midstream NGL Acquisition, which closed on December 13, 2005, included NGL extraction plants, pipelines, storage and fractionation facilities, distribution facilities, and contracts including marketing, supply and transportation arrangements, and NGL marketing infrastructure. This acquisition has extended Provident’s involvement in the NGL value chain. Results in 2005 included NGL fee for service, fixed margin extraction, equity margin on marketed NGLs, and margin on crude oil marketing contracts. The crude oil marketing contracts were disposed in May 2005, thus 2006 results include an increase in fees for services, fixed margin extraction and equity margin on marketed NGLs.

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:
 
a)
Empress East
 
b)
Redwater West
 
c)
Commercial Services

a.
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 income for this business line is primarily driven by the pricing relationship of natural gas at AECO to NGL values in Belvieu. 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 margin for this business line was $133.7 million in 2006.
 
 
b.
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% control of all products from the 38,500 bpd Younger NGL extraction plant located at Taylor in northeastern British Columbia that supplies local markets and Provident in the greater Fort Saskatchewan area.

 
·
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 450 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 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. 2006 margin for this business line was $69.5 million.

c.
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% 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. 2006 margin for this business line was $52.8 million.

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 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.

Also, see commitments disclosure in note 16 to consolidated financial statements.
 
Operations - managed NGL volumes

In 2006, Provident Midstream managed approximately 153,020 bpd compared to 64,740 bpd in 2005, an increase of 136 percent. Managed volumes are NGL products that have been purchased or received for further processing and/or sale. The significant increase in 2006 is a result of the Midstream NGL Acquisition.

2006 Midstream business unit results can be summarized as follows:


Year ended December 31,
      
($ millions)
  
2006
  
         
Empress East Margin
  
$
133.7
  
Redwater West Margin
    
69.5
 
Commercial Services Margin
    
52.8
 
Gross operating margin
    
256.0
 
Cash general and administrative expenses and other
    
(21.0
)
Realized loss on financial derivative instruments
    
(15.4
)
Midstream EBITDA
    
219.6
 


Revenues
 
For 2006 product sales and services revenue were $1,764.4 million (2005 - $908.1 million). The significant increase in revenue over 2005 is a result of the Midstream NGL Acquisition, an increase in propane plus prices in the second and third quarters of 2006 over the comparable quarters in 2005, and the commissioning of the condensate loading and terminalling facilities in the second quarter of 2006. Product sales relate to the marketing of NGLs and transportation and fractionation contracts (T&F), while service revenue relates to fees earned through NGL processing, marketing, storage and distribution. The majority of NGL revenues are earned pursuant to both long-term contracts and annual evergreen purchase and sales commitments.

In addition to the increased product sales and service revenue, Midstream revenue was reduced by $15.4 million for the year ended December 31, 2006 (2005 - $2.2 million) due to realized losses on financial derivative instruments. Midstream enters into derivative contracts to assist with margin stabilization on marketed products.

Expenses
 
For 2006 the cost of goods sold (COGS) was $1,471.2 million (2005 - $786.6 million). Cost of goods sold relates to NGL product sales revenue included in product sales and services revenue. COGS include all costs incurred in the production and purchase of NGL specification product for sale. The majority of the natural gas liquids are purchased pursuant to long-term contracts and annual evergreen purchase commitments. The significant increase in COGS over 2005 is a result of the Midstream NGL Acquisition which has resulted in an increase in managed volumes.

Operating and maintenance expenses were $22.6 million for 2006 (2005 - $36.4 million). Since the third quarter of 2006, costs include operating costs incurred to process NGLs, and provide T&F, and storage and distribution services to third parties. In prior periods, operating costs also included costs incurred at the Younger and Redwater facilities for NGLs Provident had purchased. These costs are now included in the determination of inventory and cost of goods sold, reflecting the integration of operations after the Midstream NGL Acquisition.

General and administrative expenses were $29.9 million in 2006 (2005 - $12.6 million) representing an increase in the scale of segment operations and an increased number of employees since the Midstream NGL Acquisition. As well, there were increased costs for integration and compliance activities, including costs related to the implementation of procedures and documentation in connection with the U.S. Sarbanes-Oxley Act. Interest expense for 2006 was $32.1 million (2005 - $4.9 million) reflecting an increase in capitalization associated with the Midstream NGL Acquisition. Depreciation expense was $49.1 million in 2006 (2005 - $11.8 million) reflecting the larger asset base acquired through the Midstream NGL Acquisition. The majority of the property, plant and equipment are depreciated on a straight-line basis reflecting the long useful life of these assets of 30 to 40 years.
 
Earnings before interest, taxes, depletion, depreciation, accretion, and other non-cash items (“EBITDA”) and cash flow from operations

For 2006 EBITDA increased 211 percent to $219.6 million from $70.7 million in 2005. Annual cash flow increased 178 percent to $184.4 million from $66.3 million in 2005. Through the Midstream NGL Acquisition, Provident has expanded its involvement in the NGL value chain and increased managed volumes by 136 percent to 153,020 bpd, which has made a significant contribution to the overall increase in EBITDA and cash flow. In addition, Midstream EBITDA and cash flow benefited from an increase in propane plus prices in the second and third quarters of 2006 over the comparable quarters in 2005 accompanied by a reduction in associated product costs, mostly due to reduced natural gas prices.

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

Fractionation spread support program
 
As part of the 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 until November 2007 if the fractionation spread ratio is below historic levels. This program is intended to ensure that Provident achieves the long-term average fractionation spread ratio that the NGL business has attained historically through to November 2007. This program is intended to provide consistent and stable cash flow and distributions for Unitholders. In certain circumstances, the vendor will have the ability to recover the amounts provided under the support program until October 31, 2008, if the fractionation spread ratio exceeds historic levels. Provident’s long term risk management strategy is focused on locking in fractionation spread margins, with the objective of stabilizing cash flow over the longer term.

The impact of the agreement on the 2006 results was a $5.2 million repayment in the first quarter of 2006, of an amount that was received in the fourth quarter of 2005, resulting in an increase in the cost of goods available for sale in 2006.

Capital expenditures
 
Midstream capital expenditures for 2006 totaled $66.0 million. $42.0 million of the capital was spent on the new condensate offloading facilities and truck terminals at Redwater. $9.2 million was spent on the initial drilling of two new Redwater storage caverns expected to be completed in 2009, and $11.3 million was spent to acquire an additional 7.5% of the Provident Empress NGL Extraction plant. The remaining $3.5 million relates to sustaining capital requirements.
 
Foreign ownership

Based on information received from our transfer agent and financial intermediaries in January 2007, 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., an independent engineering firm, 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.
 
Recent accounting pronouncements

Convergence of Canadian GAAP with International Financial Reporting Standards

In 2006, Canada’s Accounting Standards Board (AcSB) issued a strategic plan that will result in Canadian GAAP, as it applies to publicly accountable entities, being converged with International Financial Reporting Standards over a transitional period. The AcSB is expected to develop and release a detailed implementation plan with a transition period initially indicated to be five years. The Trust will consider the effect that this implementation plan might have on the consolidated financial statements during the transition period.

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 Trust does not expect the adoption of this standard to have a material impact on its financial statements.

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.

Discontinued operations

In April 2006, the CICA issued EIC abstract 161 “Discontinued Operations” which specifically addresses issues regarding the treatment of interest expense to be allocated to a discontinued operation, general corporate overhead expenses allocated to a discontinued operations, and reporting the results of operations of a component of the enterprise classified as held for sale as discontinued operations if the remaining operations are insignificant. The accounting treatment of the abstract may be applied prospectively and should be applied to all disposal transactions initiated after the date of issue of the abstract. The adoption of this abstract has not had a material impact on the Trust’s consolidated financial statements.

Stock-based compensation for employees eligible to retire before the vesting date

In 2006, the CICA issued EIC abstract 162 “Stock-based compensation for employees eligible to retire before the vesting date.” In this abstract, the CICA addresses the situation if an employee is eligible to receive a reward after the employee has retired and is no longer providing service to the entity. In this situation, the abstract states that the expense associated with the reward should be recognized over the period from the grant date to the date the employee becomes eligible to retire, or, in situations where the employee is eligible to retire before the grant date, the entire expense should be recognized on the grant date. The accounting treatment of this abstract should be applied retroactively, with restatement of prior periods in financial statements issued for interim and annual periods ending on or after December 31, 2006. The adoption of this abstract has not had a material impact on the Trust’s consolidated financial statements.

Variable interest entities

In 2006, the CICA issued EIC abstract 163 “Determining the variability to be considered in applying AcG-15” which provides guidance on how an entity should determine the variability to be considered in applying AcG-15- Consolidation of Variable Interest Entities. The abstract is to be applied prospectively to all entities with which an enterprise first becomes involved, and to all entities previously required to be analyzed under AcG-15 when a
 
reconsideration event has occurred, beginning the first day of the first interim or annual reporting period beginning on or after January 1, 2007. The Trust does not expect the adoption of this abstract to have a material impact on its financial statements.

Financial Instruments, Hedges and Comprehensive Income

In 2005, the CICA issued Section 3855 “Financial instruments-recognition and measurement,” Section 3865 “Hedges,” and Section 1530 “Comprehensive Income.” Under these Sections, standards for recognizing and measuring financial assets, financial liabilities and non-financial derivatives have been established. The standards will require the majority of derivatives to be classified as held for trading and will be measured at fair value with gains and losses recognized in net income in the periods in which they arise unless they are part of a hedging relationship. For hedges, the existing requirements for hedge accounting under Accounting Guideline 13 “Hedging relationships” are maintained, with the majority of hedging relationships being stated at fair value with a gain or loss from remeasuring the foreign currency component of its carrying amount being recognized in net income in the period of change together with the offsetting loss or gain on the hedged item attributable to the hedged risk. These new standards also require an entity to present comprehensive income and its components, as well as net income, in its financial statements. This will include certain gains or losses, including foreign currency translation and other amounts arising from changes in fair value. These Sections apply to interim and annual financial statements relating to fiscal years beginning on or after October 1, 2006. The Trust is currently evaluating the effect that these standards might have on the consolidated financial statements.

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 beginning on or after October 1, 2007. The Trust is currently evaluating the effect that these standards might have on the consolidated financial statements.

Equity

In 2005, the CICA issued Section 3251 “Equity”. This Section replaces Section 3250 “Surplus” and establishes standards for the presentation of equity and changes in equity during the reporting period. The Section requires an entity to present separately each of the changes in equity during the period, including comprehensive income, as well as components of equity at the end of the period. This Section applies to interim and annual financial statements relating to fiscal years beginning on or after October 1, 2006. The Trust is currently evaluating the effect that this standard might have on the consolidated financial statements.

Business risks

The trust industry is 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:
 
    · capital markets risk and the ability to finance future growth; and
 
    · the impact of Canadian governmental regulation on Provident, including the effect of proposed taxation of 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 consistent and 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 low 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 the four quarters ended December 31, 2006 on both the Toronto Stock Exchange and the New York Stock Exchange:

   
Q1
  
Q2
  
Q3
  
Q4
  
TSE – PVE.UN (Cdn$)
                  
High
  
$
13.70
  
$
14.31
  
$
14.50
  
$
13.85
  
Low
  
$
11.79
  
$
12.87
  
$
12.07
  
$
10.05
  
Close
  
$
13.04
  
$
14.00
  
$
13.02
  
$
12.84
  
Volume (000s)
    
23,113
    
29,205
   
43,411
    
35,081
 
NYSE – PVX (US$)
                          
High
  
$
11.66
  
$
12.99
  
$
13.04
  
$
12.16
  
Low
  
$
10.24
  
$
11.16
  
$
10.81
  
$
9.00
  
Close
  
$
11.32
  
$
12.37
  
$
11.75
  
$
10.92
  
Volume (000s)
    
36,038
    
29,175
    
33,378
    
35,480
 
 
Additional information

Additional information concerning Provident can be accessed under Provident’s public filings at www.sedar.com and on Provident’s website at www.providentenergy.com.
 
Selected annual financial measures

                 
($ 000s except per unit data)
  
2006
  
 2005
  
 2004
 
                     
Revenue (net of royalties and financial derivative instruments)
  
$
2,187,253
  
$
1,360,274
  
$
1,109,857
  
Net income
    
140,920
   
96,926
    
21,225
  
Net income per unit-basic
    
0.72
   
0.61
    
0.19
  
Net income per unit-diluted
    
0.72
   
0.61
    
0.19
  
Total assets
    
3,435,839
   
2,792,270
    
1,813,582
  
Long-term financial liabilities (1)
    
1,132,494
   
930,756
    
472,712
  
Declared Distributions per unit
  
$
1.44
  
$
1.44
  
$
1.44
  
(1) Includes long-term debt, asset retirement obligation, long-term financial derivative instruments and other long-term liabilities.
 
 
 
Quarterly table

       
($ 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
  
Cash flow
        
$
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
and other non-cash items
       
$
64,313
  
$
77,698
  
$
67,750
  
$
66,497
  
$
276,258
  
                                     
Cash flow
        
$
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
                                      
Cash flow
        
$
26,093
  
$
39,123
  
$
58,618
  
$
60,532
  
$
184,366
  
Net (loss) income
        
$
(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
 
                                       
(Cdn $)
                                      
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 services and marketing
                              
Managed NGL volumes (bpd)
          
163,420
   
158,941
   
144,279
   
145,732
   
153,020
 

 
Quarterly table

                           
($ 000s except for per unit and operating amounts)
  
 
 2005
       
First
  
Second
 
Third
 
Fourth
  
Annual
  
       
Quarter
  
Quarter
  
Quarter 
  
Quarter 
  
Total
  
Financial - consolidated
                                      
Revenue
        
$
322,023
  
$
300,504
  
$
295,060
  
$
442,687
  
$
1,360,274
  
Cash flow
        
$
64,137
  
$
64,435
  
$
86,318
  
$
96,298
  
$
311,188
  
Net income (loss)
        
$
(2,783
)
$
26,822
  
$
18,386
  
$
54,501
  
$
96,926
  
Net income (loss) per unit - basic and diluted
        
$
(0.02
)
$
0.17
  
$
0.11
  
$
0.32
  
$
0.61
  
Unitholder distributions
        
$
51,734
  
$
57,001
  
$
59,333
  
$
62,646
  
$
230,714
  
Distributions per unit
        
$
0.36
  
$
0.36
  
$
0.36
  
$
0.36
  
$
1.44
  
                                       
Oil and gas production
                                      
Cash revenue
        
$
100,447
  
$
104,478
  
$
124,073
  
$
117,710
  
$
446,708
  
Earnings before interest, DD&A, taxes
and other non-cash items
       
$
59,262
  
$
63,584
  
$
81,670
  
$
73,976
  
$
278,492
  
Cash flow
        
$
48,937
  
$
53,868
  
$
74,139
  
$
68,006
  
$
244,950
  
Net income (loss)
        
$
(15,046
)
$
14,681
  
$
10,702
  
$
30,437
  
$
40,774
  
                                       
Midstream services and marketing
                                      
Cash revenue
        
$
245,338
  
$
186,635
  
$
180,875
  
$
293,034
  
$
905,882
  
Earnings before interest, DD&A, taxes
       
$
16,380
  
$
11,765
  
$
12,978
  
$
29,566
  
$
70,689
  
and other non-cash items
                                      
Cash flow
        
$
15,200
  
$
10,567
  
$
12,179
  
$
28,292
  
$
66,238
  
Net income
        
$
12,263
  
$
12,141
  
$
7,684
  
$
24,064
  
$
56,152
  
                                       
Operating
                                      
Oil and gas production
                                      
Light/medium oil (bpd)
          
14,388
   
15,891
   
15,583
   
14,051
   
14,979
 
Heavy oil (bpd)
          
5,547
   
4,644
   
4,075
   
3,195
   
4,358
 
Natural gas liquids (bpd)
          
1,756
   
1,454
   
1,523
   
1,653
   
1,596
 
Natural gas (mcfd)
          
80,466
   
79,126
   
75,523
   
73,363
   
77,095
 
Oil equivalent (boed)
          
35,102
   
35,177
   
33,768
   
31,126
   
33,782
 
                                       
(Cdn $)
                                      
Average selling price net of transportation expense
                                      
Light/medium oil per bbl
        
$
49.32
  
$
51.20
  
$
62.95
  
$
55.31
  
$
54.69
  
(before realized financial derivative instruments)
                                    
Light/medium oil per bbl
        
$
40.93
  
$
42.18
  
$
49.82
  
$
42.52
  
$
43.90
  
(including realized financial derivative instruments)
                                    
Heavy oil per bbl
        
$
25.85
  
$
26.03
  
$
46.74
  
$
28.62
  
$
31.33
  
(before realized financial derivative instruments)
                                      
Heavy oil per bbl
        
$
25.78
  
$
26.03
  
$
46.74
  
$
28.62
  
$
31.31
  
(including realized financial derivative instruments)
                                      
Natural gas liquids per barrel
        
$
45.30
  
$
47.75
  
$
54.27
  
$
49.44
  
$
49.09
  
Natural gas per mcf
        
$
6.76
  
$
7.29
  
$
8.43
  
$
11.44
  
$
8.43
  
(before realized financial derivative instruments)
                                      
Natural gas per mcf
        
$
6.74
  
$
7.13
  
$
8.03
  
$
11.22
  
$
8.23
  
(including realized financial derivative instruments)
                                      
                                       
Midstream services and marketing
                                      
Managed NGL volumes (bpd)
          
61,590
   
58,200
   
61,760
   
77,100
   
64,740
 
 
 
 
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.

 
       
Thomas W. Buchanan
 Mark N. Walker
Chief Financial Officer
    
Chief Executive Officer 
      
 

Calgary, Alberta
March 7, 2007

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, 2006, our internal control over financial reporting was effective.
 
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.
 
Management s assessment of the effectiveness of the Trust s internal control over financial reporting as of December 31, 2006, has been audited by PricewaterhouseCoopers LLP, independent auditors, as stated in their report which appears herein.

 
   
Thomas W. Buchanan
 Mark N. Walker
Chief Financial Officer
    
Chief Executive Officer 
      
 

Calgary, Alberta
March 7, 2007
 

 
PricewaterhouseCoopers LLP
 
Chartered Accountants
 
111 5th Avenue SW, Suite 3100
 
Calgary, Alberta
 
Canada T2P 5L3
 
Telephone +1 (403) 509 7500
Independent Auditors’ Report
Facsimile +1 (403) 781 1825

To the Unitholders of Provident Energy Trust

We have completed an integrated audit of the consolidated financial statements and internal control over financial reporting of Provident Energy Trust (the Trust) as of December 31, 2006 and an audit of its December 31, 2005 consolidated financial statements. Our opinions, based on our audits, are presented below.

Consolidated financial statements

We have audited the accompanying consolidated balance sheets of the Trust as at December 31, 2006 and 2005, and the related consolidated statements of operations and accumulated income and cash flows for the years then ended. These financial statements are the responsibility of the Trust’s management. Our responsibility is to express an opinion on these financial statements based on our audits.
 
We conducted our audit of the Trust’s financial statements as at December 31, 2006 and for the year then ended in accordance with Canadian generally accepted auditing standards and the standards of the Public Company Accounting Oversight Board (United States). We conducted our audit of the Trust’s financial statements as at December 31, 2005 and for the year then ended in accordance with Canadian generally accepted auditing standards. Those standards require that we plan and perform an audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit of financial statements includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. A financial statement audit also includes assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation.
 
In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the financial position of the Trust as at December 31, 2006 and 2005 and the results of its operations and its cash flows for the year then ended in accordance with Canadian generally accepted accounting principles.
 
 
 

PricewaterhouseCoopers refers to the Canadian firm of PricewaterhouseCoopers LLP and the other member firms of PricewaterhouseCoopers International Limited, each
of which is a separate and independent legal entity.
 
Internal control over financial reporting

We have also audited management's assessment, included in the Management’s Report on Internal Control Over Financial Reporting to the unitholders, that the Trust maintained effective internal control over financial reporting as of December 31, 2006, based on criteria established in Internal Control - Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). The Trust’s management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting. Our responsibility is to express opinions on management’s assessment and on the effectiveness of the Trust’s internal control over financial reporting based on our audit.
 
We conducted our audit of internal control over financial reporting in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. An audit of internal control over financial reporting includes obtaining an understanding of internal control over financial reporting, evaluating management’s assessment, testing and evaluating the design and operating effectiveness of internal control, and performing such other procedures as we consider necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinions.
 
A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (i) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (ii) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (iii) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.
 
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.

In our opinion, management’s assessment that the Trust maintained effective internal control over financial reporting as at December 31, 2006 is fairly stated, in all material respects, based on criteria established in Internal Control — Integrated Framework issued by the COSO. Furthermore, in our opinion, the Trust maintained, in all material respects, effective internal control over financial reporting as of December 31, 2006 based on criteria established in Internal Control — Integrated Framework issued by the COSO.
 

Chartered Accountants
Calgary, Alberta
March 7, 2007
 

 
Comments by Auditor on Canada - U.S. reporting differences
 
In the United States, reporting standards for auditors require the addition of an explanatory paragraph (following the opinion paragraph) when there is change in accounting principles that has a material effect on the comparability of the Trust’s financial statements, such as the changes described in Note 18 to the Consolidated Financial Statements. Our report is expressed in accordance with Canadian reporting standards which do not require a reference to such a change in accounting principles in the auditors’ report when the change is properly accounted for and adequately disclosed in the financial statements.
         
CONSOLIDATED BALANCE SHEETS
          
Canadian dollars (000s)
          
   
As at
 
As at
 
 
 
December 31,
 
December 31,
 
 
 
2006
 
2005
  
Assets
              
Current assets
              
Cash and cash equivalents
  
$
10,302
  
$
32,113
  
Accounts receivable
    
270,135
    
267,246
  
Petroleum product inventory
    
85,868
    
110,638
  
Prepaid expenses
    
16,381
    
14,326
  
Financial derivative instruments (note 14)
    
43,337
    
-
  
     
426,023
    
424,323
  
Cash reserve for future site reclamation (note 15)
    
-
    
1,872
  
Investments
    
4,320
    
3,758
  
Deferred financing charges
    
12,351
    
14,710
  
Property, plant and equipment (note 5)
    
2,333,537
    
1,702,689
  
Intangible assets (note 6)
    
193,592
    
215,850
  
Goodwill (note 3)
    
431,353
    
429,068
  
Long-term financial derivative instruments (note 14)
    
34,663
    
-
  
   
$
3,435,839
  
$
2,792,270
  
Liabilities
              
Current liabilities
              
Accounts payable and accrued liabilities
  
$
295,003
  
$
309,704
  
Cash distributions payable
    
21,506
    
20,644
  
Distributions payable to non-controlling interests
    
677
    
452
  
Financial derivative instruments (note 14)
    
53,068
    
14,149
  
     
370,254
    
344,949
  
               
Long-term debt - revolving term credit facilities (note 7)
    
702,993
    
586,597
  
Long-term debt - convertible debentures (note 7)
    
285,792
    
298,007
  
Asset retirement obligation (note 9)
    
49,614
    
41,133
  
Long-term financial derivative instruments (note 14)
    
77,790
    
-
  
Other long-term liabilities (note 12)
    
16,305
    
5,019
  
Future income taxes (note 13)
    
309,006
    
91,595
  
Non-controlling interests (note 10)
              
USOGP operations
    
81,111
    
11,885
  
Exchangeable shares
    
-
    
8,259
  
               
Unitholders’ equity
              
Unitholders’ contributions (note 11)
    
2,254,048
    
1,971,707
  
Convertible debentures equity component
    
18,522
    
19,301
  
Contributed surplus (note 12)
    
1,315
    
1,675
  
Cumulative translation adjustment
    
(42,294
)
  
(41,785
)
Accumulated income
    
238,208
    
97,288
  
Accumulated cash distributions
    
(926,825
)
  
(643,360
)
     
1,542,974
    
1,404,826
  
   
$
3,435,839
  
$
2,792,270
  

On behalf of the Board of Directors:
 
 
 
M.H. (Mike) Shaikh, CA
 
Thomas W. Buchanan, CA
Director
 
Director

-1-
 
 
PROVIDENT ENERGY TRUST
CONSOLIDATED STATEMENT OF OPERATIONS AND ACCUMULATED INCOME
Canadian dollars (000s except per unit amounts)

   
Year ended
   
December 31,
   
2006
  
2005
  
Revenue (note 8)
              
Revenue
  
$
2,244,107
  
$
1,419,450
  
Realized loss on financial derivative instruments
    
(13,540
)
  
(66,860
)
Unrealized (loss) gain on financial derivative instruments
    
(43,314
)
  
7,684
  
     
2,187,253
    
1,360,274
  
Expenses
              
Cost of goods sold
    
1,471,171
    
786,564
  
Production, operating and maintenance
    
172,253
    
171,193
  
Transportation
    
19,786
    
6,932
  
Depletion, depreciation and accretion
    
249,139
    
193,236
  
General and administrative (note 12)
    
97,288
    
51,361
  
Interest on bank debt
    
34,666
    
10,875
  
Interest and accretion on convertible debentures
    
23,919
    
19,643
  
Amortization of deferred financing charges
    
3,854
    
1,409
  
Foreign exchange gain and other
    
(2,319
)
  
(3,244
)
Gain on sale of assets (note 4)
    
-
    
(5,188
)
     
2,069,757
    
1,232,781
  
               
Income before taxes and non-controlling interests
    
117,496
    
127,493
  
               
Capital tax expense
    
1,314
    
4,780
  
Current and withholding taxes
    
5,829
    
5,628
  
Future income tax (recovery) expense (note 13)
    
(34,316
)
  
17,793
  
     
(27,173
)
  
28,201
  
Net income before non-controlling interests
    
144,669
    
99,292
  
Non-controlling interests (note 10)
              
USOGP operations
    
2,995
    
1,596
  
Exchangeable shares
    
754
    
770
  
Net income
    
140,920
    
96,926
  
               
Accumulated income, beginning of year
  
$
97,288
  
$
362
  
Accumulated income, end of year
  
$
238,208
  
$
97,288
  
Net income per unit - basic
  
$
0.72
  
$
0.61
  
Net income per unit - diluted
  
$
0.72
  
$
0.61
  

-2-
 
 
PROVIDENT ENERGY TRUST
          
CONSOLIDATED STATEMENT OF CASH FLOWS
          
Canadian Dollars (000s)
          
   
Year ended
 
 
December 31,
   
2006
 
2005
  
Cash provided by operating activities
              
Net income for the year
  
$
140,920
  
$
96,926
  
Add (deduct) non-cash items:
              
Depletion, depreciation and accretion
    
249,139
    
193,236
  
Debenture accretion and amortization of deferred charges
    
6,357
    
4,090
  
Non-cash unit based compensation (notes 12 and 17)
    
23,083
    
9,753
  
Unrealized loss (gain) on financial derivative instruments (note 8)
    
43,314
    
(7,684
)
Unrealized foreign exchange loss (gain) and other
    
418
    
(356
)
Future income tax (recovery) expense (note 13)
    
(34,316
)
  
17,793
  
Net income attributable to non-controlling interests
    
3,749
    
2,366
  
Equity in loss of investee
    
-
    
252
  
Gain on sale of assets (note 4)
    
-
    
(5,188
)
Cash flow from operations before changes in working capital
              
and site restoration expenditures
    
432,664
    
311,188
  
Site restoration expenditures (note 15)
    
(4,622
)
  
(2,481
)
Change in non-cash operating working capital
    
(13,693
)
  
(51,344
)
     
414,349
    
257,363
  
Cash provided by financing activities
              
Increase in long-term debt
    
117,385
    
325,771
  
Declared distributions to unitholders
    
(283,465
)
  
(230,714
)
Declared distributions to non-controlling interests
    
(6,523
)
  
(3,360
)
Issue of trust units, net of issue costs
    
257,076
    
395,805
  
Contributions by non-controlling interests (note 10)
    
135,829
    
-
  
Issue of debentures, net of issue costs
    
-
    
239,822
  
Redemption of debentures, net of costs
    
-
    
(2,997
)
Change in non-cash financing working capital
    
(154
)
  
(50
)
     
220,148
    
724,277
  
Cash used for investing activities
              
Capital expenditures
    
(190,433
)
  
(156,499
)
Acquisition of Midstream NGL business (note 3)
    
(1,036
)
  
(772,303
)
Acquisition of Nautilus
    
-
    
(91,420
)
Increase in investment
    
-
    
(1,010
)
Oil and gas property acquisitions (note 3)
    
(480,357
)
  
(586
)
(Payments) proceeds from property dispositions
    
(1,268
)
  
45,100
  
Proceeds on sale of assets (notes 3 and 4)
    
11,517
    
29,295
  
Reclamation fund contributions
    
(2,750
)
  
(2,899
)
Reclamation fund withdrawals (note 15)
    
4,622
    
2,481
  
Payment of financial derivative instruments
    
-
    
(7,192
)
Change in non-cash investing working capital
    
3,397
    
5,262
  
     
(656,308
)
  
(949,771
)
(Decrease) increase in cash and cash equivalents
    
(21,811
)
  
31,869
  
Cash and cash equivalents beginning of year
    
32,113
    
244
  
Cash and cash equivalents end of year
  
$
10,302
  
$
32,113
  
Supplemental disclosure of cash flow information
              
Cash interest paid including debenture interest
  
$
56,036
  
$
23,946
  
Cash taxes paid
  
$
9,601
  
$
12,026
  
-3-
 
 
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

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

December 31, 2006

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 are accounted for using the cost method. Certain comparative numbers have been restated to conform with the current year presentation.
 
(ii)  
Financial derivative instruments
 
 
All derivative financial instruments are recorded on the balance sheet at fair value and changes in fair value are recognized in income as unrealized gains or losses on financial derivative instruments in the period in which the change occurs. Actual gains or losses are recorded as realized gains or losses on financial derivative instruments in the period that the instrument is settled.
 
(iii)  
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 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)  
Ceiling test
 
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.

(v)  
Joint Venture
 
 
Provident conducts many of its activities through joint ventures and the accounts reflect only Provident’s proportionate interest in such activities.
 
(v)  
Inventory
 
 
Inventories of products are valued at the lower of average cost and net realizable value based on market prices.
 
(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 deferred and recognized in earnings over the vesting period of the options with a corresponding increase in contributed surplus.
 
-5-
 
 
 
The Trust has established other unit based compensation plans whereby notional units are granted to employees. The fair value of these notional units is estimated and recorded as an expense to non-cash unit based compensation (included in general and administrative expenses) with an offsetting amount to accrued liabilities. A realization of the expense and a resulting reduction in cash provided by operating activities occurs when a cash payment is made.
 
(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 exchangeable shares and convertible debentures is determined using the "if- converted" method whereby the outstanding exchangeables and debentures at the end of the period are assumed to have been exchanged or converted at the beginnning of the period or at the time of issue if issued during the year. Amounts charged to income or loss relating to the outstanding exchangeable shares and debentures are added back to net income for the diluted calculation. The units issued upon exchange or conversion are included in the denominator of per unit - basic calculations from the date of issue.
 
(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 taxable only on income that is not distributed or distributable to the unitholders. As the Trust distributes all of its taxable income to the unitholders and meets the requirements of the Income Tax Act (Canada) applicable to the Trust, no provision for income taxes has been made in the Trust.
 
(xii)  
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 separate component of unitholders’ equity.
 
 
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.
 
-6-
 
 
 (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, and asset retirement obligation. The ceiling test uses factors such as estimated reserves, production rates, estimated future petroleum and natural gas prices and future costs. Due to the inherent limitations in metering and the physical properties of storage caverns and pipelines, the determination of precise volumes of natural gas liquids held in inventory at such locations is subject to estimation. Actual inventories of natural gas liquids can only be determined by draining of the caverns. By their very nature, these estimates are subject to measurement uncertainty and the effect on the financial statements of future periods could be material.
 
 
 
The estimation of oil and gas reserves is a subjective process. Forecasts are based on engineering data, projected future rates of production, estimated commodity prices, and 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.    
Acquisitions
 
i)  
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 assets provide daily production of approximately 5,500 barrels of oil equivalent, over 90 percent of which is natural gas, and over 200 identified drilling locations. 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.
 
ii)  
Acquisition of Midstream NGL assets
On December 13, 2005 Provident acquired midstream business assets (the Midstream NGL Acquisition) from EnCana Corporation by way of the purchase of partnership interests, corporations and assets. The business comprises NGL extraction plants, pipelines, storage and fractionation facilities, distribution facilities, contracts including supply and transportation arrangements, and ownership of Kinetic Resources, two partnerships which perform NGL marketing services including Kinetic’s interests in a distribution terminal and leases on approximately 700 rail cars. The transaction was accounted for using the purchase method with the allocation of the purchase as follows:
-7-
 
 
Net assets acquired and liabilities assumed
      
Property, plant and equipment
$
426,817
  
Working capital, net of cash acquired
  
38,937
  
Intangible asset - contracts and customer relationships
  
183,100
  
Intangible asset - fractionation spread support agreement
  
17,600
  
Intangible assets - other
  
16,308
  
Goodwill
  
100,409
  
Financial derivative instruments
  
945
  
Asset retirement obligation
  
(7,604
)
Future income taxes
  
(3,173
)
 
$
773,339
  
Consideration
      
Acquisition costs
$
12,179
  
Cash, net of cash acquired
  
761,160
  
 
$
773,339
  

The Midstream NGL Acquisition was financed by the issue of 21,830,000 units at $12.60 per unit and $150 million of 6.5 percent convertible unsecured subordinated debentures. The remaining portion of the purchase price of the Midstream NGL Acquisition was funded through Provident’s credit facility.
 
In February 2006, Provident sold its 49 percent interest in the Marysville Partnership, which owns the Marysville Underground Storage Terminal (MUST), for net cash proceeds of $11.5 million. The partnership interest was part of the assets acquired in the Midstream NGL acquisition. The purchase price allocation of the Midstream NGL acquisition was adjusted to reflect the revised fair value of the acquisition, resulting in an increase to goodwill amounting to $2.0 million.
 
In June 2006, Provident settled the final post-closing adjustments relating to the acquisition. The net cash payment resulted in an increase to goodwill amounting to $2.3 million.
 
In December 2006, Provident adjusted its estimate of acquisition costs relating to the acquisition. The purchase price allocation was adjusted to reflect the revised fair value of the acquisition, resulting in a decrease in goodwill of $2.0 million.
 
4.   
Sale of assets
 
On May 1, 2005, certain oil purchase and sale contracts were sold for net proceeds of $5.5 million and a gain of $5.2 million was recorded net of disposal costs.
 
On December 29, 2005, a parcel of land in California was sold for net proceeds of $23.8 million. The sale represents surface rights for real estate development, with no impact on oil and gas reserves. The transaction resulted in a deferred gain of $1.0 million. The purchaser has agreed to complete the removal and relocation of oilfield infrastructure and environmental remediation work. Not included in the net proceeds or deferred gain are contingent proceeds, amounting to $2.7 million, which are held in escrow until this work is completed.
 
-8-
 
5.   
Property, plant and equipment
 
       
Accumulated
      
       
depletion and
  
Net Book
  
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
  
 
 
          
Accumulated
        
 
          
depletion and
 
  
Net Book
  
December 31, 2005
    
Cost
    
depreciation
    
value
  
Oil and natural gas properties
  
$
1,710,998
  
$
731,336
  
$
979,662
  
Midstream assets
    
738,835
    
21,951
    
716,884
  
Office equipment
    
12,423
    
6,280
    
6,143
  
Total
  
$
2,462,256
  
$
759,567
  
$
1,702,689
  

Costs associated with unproved properties excluded from costs subject to depletion as at December 31, 2006 totaled $17.8 million (December 31, 2005 - $23.8 million). Asset retirement costs of $49.9 million are included in property, plant and equipment (December 31, 2005 - $38.6 million). Midstream assets include $22.0 million (2005 - $29.3 million) for products required for line-fill and cavern bottoms.
 
An impairment test calculation was performed on property, plant and equipment at December 31, 2006 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, 2006:

   
Oil
 
Gas
 
NGL
 
Year
 
$/bbl
 
$/mcf
 
$/bbl
  
2007
  
$
50.87
  
$
7.00
  
$
51.66
  
2008
  
$
50.97
  
$
7.57
  
$
52.14
  
2009
  
$
50.18
  
$
7.81
  
$
50.85
  
2010
  
$
51.23
  
$
7.79
  
$
50.26
  
2011
  
$
51.00
  
$
7.78
  
$
49.74
  
Thereafter (1)
    
2.00
%
  
2.00
%
  
2.00
%
(1) Percentage change represents the increase in each year after 2011 to the end of the reserve life.
      
 
-9-
 
 
6.    
Intangible assets
 
           
Accumulated
    
Net Book
  
December 31, 2006 
    
Cost
    
amortization
    
value
  
                     
Midstream and marketing contracts and customer relationships
  
$
183,100
  
$
12,842
  
$
170,258
  
Fractionation spread support arrangement
    
17,600
    
9,258
    
8,342
  
Other intangible assets
    
16,308
    
1,316
    
14,992
  
Total
  
$
217,008
  
$
23,416
  
$
193,592
  
 
 
           
Accumulated
    
Net Book
  
December 31, 2005    
Cost
    
amortization
    
value
  
                     
Midstream and marketing contracts and customer relationships
  
$
183,100
  
$
635
  
$
182,465
  
Fractionation spread support arrangement
    
17,600
  
$
458
    
17,142
  
Other intangible assets
    
16,308
  
$
65
    
16,243
  
Total
  
$
217,008
  
$
1,158
  
$
215,850
  
 
 
7.     
Long-term debt
 
     
December 31,
2006
    
December 31,
2005
  
Revolving term credit facilities
  
$
702,993
  
$
586,597
  
Convertible debentures
    
285,792
    
298,007
  
   
$
988,785
  
$
884,604
  

(i)  
Revolving term credit facilities
 
 
Provident has a $925 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, 2005 the facility totaled $750 million. In July 2006 the facility was increased to its current level of $925 million. At December 31, 2006, $691.9 million was drawn on this facility.
 
 
The terms of the credit facility have a revolving three year period expiring on May 30, 2009. 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 addition, Provident’s U.S. subsidiaries have credit facilities with a borrowing base of U.S. $158 million with a syndicate of U.S. banks secured by oil and gas assets of the subsidiaries. Provident 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 and the current borrowing base is reviewed every six month period. At December 31, 2006, $11.1 million was drawn on these facilities.
 
 
At December 31, 2006 the effective interest rate of the outstanding credit facilities was 5.2 percent (2005 - 4.6 percent). At December 31, 2006 Provident had $31.9 million in letters of credit outstanding (2005 - $45.1 million) that guarantee Provident’s performance under certain commercial and other contracts.
 
(ii)  
Convertible debentures
 
On November 15, 2005 the Trust issued $150.0 million of unsecured convertible subordinated debentures ($143.8 million net of issue costs) with a 6.5 percent coupon rate maturing April 30, 2011. Issue costs have been classified as deferred financing charges. The debentures may be converted into trust units at the option of the holder at a conversion price of $14.75 per trust unit prior to April 30, 2011 and may be redeemed by the Trust under certain circumstances. The unsecured subordinated convertible debentures were initially recorded at fair value of $141.4 million. The difference between the fair value and proceeds of $8.6 million was recorded as equity.
On May 31, 2005 the Trust completed the redemption of its 10.5 percent convertible unsecured subordinated debentures that were originally scheduled to mature May 15, 2007. A total of 3.5 million units were issued at the conversion price of $10.70 per unit. A further $3.0 million cash was paid to the remaining debenture holders that did not convert to trust units at $1,050 for each $1,000 of convertible debenture held plus accrued interest to May 31, 2005 resulting in a loss on redemption of $49,000. Unamortized deferred debt issue costs of $2.5 million, originally incurred on the issue of the 10.5 percent convertible debentures, were reclassified to trust unit issue costs as a result of the issue of 3.5 million trust units.

On March 1, 2005 the Trust issued $100.0 million of unsecured convertible subordinated debentures ($95.8 million net of issue costs) with a 6.5 percent coupon rate maturing August 31, 2012. Issue costs have been classified as deferred financing charges. The debentures may be converted into trust units at the option of the holder at a conversion price of $13.75 per trust unit prior to August 31, 2012 and may be redeemed by the Trust under certain circumstances. The unsecured subordinated convertible debentures were initially recorded at fair value of $92.6 million. The difference between the fair value and proceeds of $7.4 million was recorded as equity.
 

The Trust may elect to satisfy interest and principal obligations by the issue of trust units. For the twelve months ended December 31, 2006, $15.4 million of the face value of debentures were converted to trust units at the election of debenture holders (2005 - $109.3 million, including $45.7 million associated with the May 31, 2005 redemption of the 10.5 percent convertible unsecured subordinated debentures). The following table details each outstanding convertible debenture.

Convertible Debentures
  
December 31, 2006
 
December 31, 2005
          
                        
Conversion
  
   
Carrying
  
Face
  
Carrying
  
 Face
      
Price per
  
($ 000s except conversion pricing)
  
Value (1)
  
Value
  
Value (1)
  
 Value
  
Maturity Date
  
unit (2)
  
6.5% Convertible Debentures
  
$
142,860
  
$
150,000
  
$
141,522
  
$
150,000
    
April 30, 2011
    
14.75
  
6.5% Convertible Debentures
    
93,134
    
99,024
    
92,482
    
99,179
    
Aug. 31, 2012
    
13.75
  
8.0% Convertible Debentures
    
24,402
    
25,114
    
32,382
    
33,648
    
July 31, 2009
    
12.00
  
8.75% Convertible Debentures
    
25,396
    
25,972
    
31,621
    
32,659
    
Dec. 31, 2008
    
11.05
  
   
$
285,792
  
$
300,110
  
$
298,007
  
$
315,486
              

(1)  
Excluding equity component of convertible debentures.
(2)  
The debentures may be converted into trust units at the option of the holder of the debenture at the conversion price per unit.

8
.
Revenue
            

   
Year ended December 31,
   
2006
  
2005
  
Gross production revenue
  
$
578,255
  
$
621,761
  
Product sales and service revenue
    
1,764,392
   
908,111
 
Royalties
    
(98,540
)
  
(110,422
)
Revenue
    
2,244,107
   
1,419,450
 
               
Realized loss on financial derivative instruments
    
(13,540
)
  
(66,860
)
Unrealized (loss) gain on financial derivative instruments
    
(43,314
)
  
7,684
 
   
$
2,187,253
  
$
1,360,274
  
               
Change in unrealized loss on financial derivative instruments
  
$
(43,314
)
$
9,828
  
Amortization of loss on financial derivative instruments
    
-
   
(2,144
)
Unrealized (loss) gain on financial derivative instruments
  
$
(43,314
)
$
7,684
  
 
The realized loss on financial derivative instruments for the year ended December 31, 2006 of $13.5 million (2005 - $66.9 million) relates to the cash settlement on derivative instruments.
 
 
 
9.    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 $411.6 million (2005 - $293.0 million). Payments to settle oil and gas asset retirement obligations occur over the operating lives of the assets estimated to be from three to 49 years.
 
The total undiscounted amount of future cash flows required to settle the midstream services and marketing asset retirement obligations is estimated to be $166.1 million (2005 - $179.3 million). The estimated costs include such activities as dismantling, demolition and disposal of the facilities as well as remediation and restoration of the surface land. Payments to settle the midstream services and marketing asset retirement obligations are expected to occur subsequent to the closure of the facilities and related assets. Settlement of these obligations is expected to occur in 30 to 45 years.

   
Year ended December 31,
   
2006
  
2005
  
Carrying amount, beginning of year
  
$
41,133
  
$
40,506
  
Acquisitions
    
1,903
   
9,161
 
Change in estimate
    
6,793
   
2,884
 
Increase in liabilities incurred during the period
    
1,443
   
1,784
 
Settlement of liabilities during the period
    
(4,622
)
  
(2,614
)
Decrease in liabilities due to disposition
    
(946
)
  
(13,612
)
Accretion of liability
    
3,910
   
3,024
 
Carrying amount, end of year
  
$
49,614
  
$
41,133
  
 
 
10.     Non-controlling interests
              

(i)  
USOGP operations

Year ended December 31,
  
2006
  
2005
  
Non-controlling interest, beginning of year
    $  11,885    $  13,649  
Net income attributable to non-controlling interest
    
2,995
   
1,596
 
Distributions to non-controlling interest holders
    
(6,523
)
  
(3,360
)
Investments by non-controlling interest
    
72,754
   
-
 
Non-controlling interest, end of year
  
$
81,111
  
$
11,885
  
Accumulated income attributable to non-controlling interest
  
$
5,514
  
$
2,519
  
 
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, 2006 to approximately 4.4 percent (2005 - 4.4 percent). Contributions by this non-controlling interest total $0.5 million in 2006 (2005 - nil).
 
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 $3.7 million in 2006.
 
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
-12-
 
 
 
offering, including an underwriter’s option, of 6,900,000 common units at U.S. $18.50 per unit, resulted in approximately 34 percent of the MLP held by partners not controlled by Provident. Contributions by this non-controlling interest total $131.6 million in 2006. Non-controlling interest was increased by $68.5 million as a result of this transaction. The difference of $63.1 million has been recorded against property, plant and equipment in accordance with full cost accounting principles.
 
(ii)  
Exchangeable shares
 
 
The non-controlling interest on the consolidated balance sheet consists of the fair value of the exchangeable shares upon issue plus the accumulated earnings attributable to the non-controlling interest. The net income attributable to the non-controlling interest on the consolidated statement of operations represents the cumulative share of net income attributable to the non-controlling interest based on the trust units issuable for exchangeable shares in proportion to total trust units issued and issuable at each quarter end during the year. In 2006, all outstanding exchangeable shares were converted into Provident trust units.
 
 
Following is a summary of the non-controlling interest - exchangeable shares for years ended December 31, 2006 and 2005:
 

Year ended December 31,
  
2006
  
2005
  
Non-controlling interest, beginning of year
  
$
8,259
  
$
35,921
  
Reduction of book value for conversion to trust units
    
(9,013
)
  
(28,432
)
Net income attributable to non-controlling interest
    
754
    
770
  
Non-controlling interest, end of year
  
$
-
  
$
8,259
  
Accumulated income attributable to non-controlling interest
  
$
-
  
$
2,252
  

The following table details the number of exchangeable shares converted and outstanding in addition to the associated book value:

       
 Year ended December 31,
      
   
2006
  
2005
  
                           
Exchangeable shares
                          
Provident Acquisitions Inc.
 Number of units
    
Amount
    
Number of units
    
Amount
  
Balance at beginning of year
    
-
  
$
-
    
336,876
  
$
3,675
  
Converted to trust units
    
-
    
-
    
(336,876
)
  
(3,675
)
Balance, end of year
    
-
    
-
    
-
    
-
  
Exchange ratio, end of year
    
-
          
-
        
Trust units issuable upon conversion, end of year
    
-
  
$
-
    
-
  
$
-
  
                           
Exchangeable shares
                          
Provident Energy Ltd.
                          
Balance at beginning of year
    
463,545
  
$
4,961
    
638,474
  
$
6,833
  
Converted to trust units
    
(463,545
)
  
(4,961
)
  
(174,929
)
  
(1,872
)
Balance, end of year
    
-
    
-
    
463,545
    
4,961
  
Exchange ratio, end of year
    
-
          
1.50962
        
Trust units issuable upon conversion, end of year
    
-
  
$
-
    
699,777
  
$
4,961
  
                           
Exchangeable shares (Series B)
                          
Provident Energy Ltd.
                          
Balance at beginning of year
    
91,320
  
$
1,046
    
2,095,271
  
$
23,931
  
Converted to trust units
    
(91,320
)
  
(1,046
)
  
(2,003,951
)
  
(22,885
)
Balance, end of year
    
-
    
-
    
91,320
    
1,046
  
Exchange ratio, end of year
    
-
          
1.19311
        
Trust units issuable upon conversion, end of year
    
-
  
$
-
    
108,955
  
$
1,046
  
Total Trust units issuable upon conversion
                          
of all exchangeable shares, end of year
    
-
  
$
-
    
808,732
  
$
6,007
  
 
-13-
 
 
11.      
Unitholders’ contributions
 
 
The Trust has authorized capital of an unlimited number of common voting trust units.
 
 
Trust units are redeemable at any time on demand by the holders thereof. Upon receipt of a redemption request by the Trust, the holder is entitled to receive a price per trust unit (the “Market Redemption Price”) equal to the lesser of: (i) 90% of the simple average of the closing price of the trust units on the principal market on which the trust units are quoted for trading during the 10 trading day period commencing immediately after the date on which the trust units are surrendered for redemption; and (ii) the closing market price on the principal market on which the trust units are quoted for trading on the date that the trust units are surrendered for redemption.
 
 
The aggregate Market Redemption Price payable by the Trust in respect of any trust units surrendered for redemption during any calendar month shall be satisfied by way of a cash payment on the last day of the following month. Total cash payments for redemption are limited to an annual maximum of $250,000. Any excess over the maximum may be satisfied by distributing notes having an aggregate principal amount equal to the aggregate Market Redemption Price of the trust units tendered for redemption.
 
(i)  
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.
 
(ii)  
2005 activity
 
 
On March 1, 2005 the Trust issued 8.4 million units at $12.00 per unit for proceeds of $100.8 million ($95.6 million net of issue costs) pursuant to a February 18, 2005 public offering.
 
 
On November 15, 2005 the Trust issued 21.83 million Subscription Receipts at a price of $12.60 per Subscription Receipt for total proceeds of $275.1 million ($261.0 million net of issue costs). Each Subscription Receipt entitled the holder to receive one trust unit upon completion of the Midstream NGL Acquisition. The acquisition closed on December 13, 2005 at which time all of the outstanding Subscription Receipts were converted to trust units. At that time, the holders of the Subscription Receipts were also entitled to $0.12 per trust unit, which is the equivalent of the November distribution paid in December. This payment was treated as a reduction to the proceeds received for the units issued through the Subscription Receipts to $12.48 per trust unit, reducing the amount attributed to Unitholders’ contributions by $2.6 million. Proceeds from the issue were used to fund the Midstream NGL Acquisition.
 
 
In 2005 the Trust issued 16.3 million units related to Provident’s DRIP program, conversion of exchangeable shares to units, conversion and redemption of convertible debentures to units and units issued pursuant to Provident’s Unit Option Plan. The net increase in unitholders’ contributions associated with these activities was $181.8 million.
 
       
Year ended December 31,
      
   
2006
2005
  
Trust Units
  
Number of units
  
Amount (000s)
  
Number of units
  
Amount (000s)
  
Balance at beginning of year
    
188,772,788
  
$
1,971,707
    
142,226,248
  
$
1,438,393
  
Issued for cash
    
16,325,000
    
224,142
    
30,230,000
    
373,238
  
Exchangeable share conversions
    
881,083
    
9,012
    
2,971,217
    
28,432
  
Issued pursuant to unit option plan
    
907,201
    
8,589
    
2,265,179
    
23,435
  
Issued pursuant to the distribution reinvestment plan
    
2,714,636
    
33,045
    
1,330,156
    
16,438
  
To be issued pursuant to the distribution reinvestment plan
300,134
    
3,806
    
107,000
    
2,005
  
Debenture conversions
    
1,327,565
    
15,689
    
6,135,418
    
64,808
  
Redemption of the 10.5% debentures (note 7)
    
-
    
-
    
3,507,570
    
46,707
  
Unit issue costs
    
-
    
(11,942
)
  
-
    
(21,749
)
Balance at end of year
    
211,228,407
  
$
2,254,048
    
188,772,788
  
$
1,971,707
  
The basic per trust unit amounts for 2006 were calculated based on the weighted average number of units outstanding of 196,627,060 (2005 - 159,315,847). The diluted per trust unit amounts for 2006 are calculated including an additional 286,957 trust units (2005 - 369,566) for the effect of the unit option plan. Provident’s convertible debentures are not included in the computation of diluted earnings per unit as their effect is anti- dilutive.
 
12.     
Unit based compensation
 
(i)  
Restricted/Performance units
 
 
Certain employees of the Trust’s Canadian 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 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, 2006 there were 571,423 RTUs and 1,704,234 PTUs outstanding (2005 - 226,055 RTUs and 464,291 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, 2006, $2.3 million (2005 - $1.0 million) is included in accounts payable and accrued liabilities for this plan and $13.3 million (2005 - $2.5 million) is included in other long-term liabilities. The following table reconciles the expense recorded for RTUs and PTUs.
 

Year ended December 31,
  
2006
  
2005
  
Cash general and administrative
  
$
1,021
  
$
-
  
Non-cash unit based compensation (included in general and administrative)
  
11,156
    
2,600
  
Operating expense
    
939
    
-
  
   
$
13,116
  
$
2,600
  

(ii)  
Unit option plan
 
 
The Trust option plan (the “Plan”) is administered by the Board of Directors of Provident. Under the Plan, all directors, officers and employees of Provident were eligible to participate in the Plan. There are 8,000,000 trust units reserved for the Trust option plan. Options were granted at a “strike price” which is not less than the closing price of the units on the Toronto Stock Exchange on the last trading day preceding the grant. In certain circumstances, based upon the cash distributions made on the trust units, the strike price may be reduced at the time of exercise of the option at the discretion of the option holder. Options vest six months after grant and every year thereafter in equal increments. In October 2005, a restricted/performance unit program (see (i)) was approved. This program replaces the unit option plan. Unit options in existence will continue to be outstanding.
-15-
 
 
Year ended December 31,
  
2006
      
2005
       
   
 
 
Weighted
 
 
 
 Weighted
 
 
 
Number of
 
Average
 
Number of
 
 Average
 
 
 
Options
 
Exercise Price
 
Options
 
 Exercise Price
  
Outstanding, beginning of year
    
3,205,625
  
$
11.11
    
5,200,331
  
$
11.01
  
Granted
    
-
    
-
    
296,200
    
11.73
  
Exercised
    
(907,201
)
  
11.13
    
(2,265,179
)
  
10.97
  
Forfeited
    
(183,616
)
  
11.08
    
(25,727
)
  
10.97
  
Outstanding, end of year
    
2,114,808
  
$
11.09
    
3,205,625
  
$
11.11
  
Exercisable, end of year
    
1,947,989
  
$
11.08
    
2,206,801
  
$
11.12
  

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 is 1.96 years and the weighted average exercise price is $11.09 per unit excluding average potential reductions to the strike prices of $1.50 per unit.
 
At December 31, 2005, the Trust had 3,205,625 options outstanding with strike prices ranging from $8.91 and $12.14 per unit. The weighted average remaining contractual life of the options was 2.20 years and the weighted average exercise price was $11.11 per unit excluding average potential reductions to the strike prices of $1.16 per unit.
 
In 2006 the Trust recorded non-cash unit based compensation expense of $0.2 million, for the 5.6 million options granted on or after January 1, 2003 (2005 - $1.1 million).
 
As at December 31, 2006, the following assumptions are the weighted averages of the individual assumptions applied at each grant date to arrive at an estimate of fair value of all granted options on or after January 1, 2003 of $3.8 million:
 
 
2005 Granted
Options
2004 Granted
Options
2003 Granted
Options
Expected annual dividend
8.00%
8.00%
8.00%
Expected volatility
19.88%
20.18%
19.46%
Risk - free interest rate
3.26%
3.30%
3.66%
Expected life of option (yrs)
3.31
3.31
3.31
Expected forfeitures
-
-
-
Fair Value of Granted Options
$0.2 million
$1.2 million
$2.4 million
 
The remaining fair value of the rights of $0.1 million, less any future cancellations, will be recognized in earnings over the remaining vesting period of the rights outstanding. The following table reconciles the movement in the contributed surplus balance.

Year ended December 31,
  
2006
  
2005
  
Contributed surplus, beginning of the year
  
$
1,675
  
$
2,002
  
Non-cash unit based compensation (included in general and administrative)
    
203
    
1,055
  
Benefit on options exercised charged to unitholders’ equity
    
(563
)
  
(1,382
)
Contributed surplus, end of year
  
$
1,315
  
$
1,675
  

(iii)  
Unit appreciation rights
 
 
Certain employees of the Trust’s U.S. subsidiaries are granted unit appreciation rights (UARs) which entitle the employee to receive cash compensation in relation to the value of a specific number of underlying notional trust units. UARs vest evenly over a period of three years commencing one year after grant and expire after four years.
 
 
The UARs upon vesting, provide certain employees entitlement to receive a cash payment equal to the excess of the market price of the Trust’s units over the exercise price of the right less notionally accrued distributions in excess of an eight percent return. These prices are denominated in U.S. dollars and are based on quoted U.S. distributions and market prices.
 
-16-
 
 
The fair value associated with the UARs is expensed in the statement of operations over the vesting period. At December 31, 2006, $2.5 million (2005 - $0.7 million) is included in accounts payable and accrued liabilities for this plan and $0.1 million (2005 - $0.7 million) is included in other long-term liabilities. The following table reconciles the expense recorded for UARs.
 
Year ended December 31,
  
2006
 
2005
 
Cash general and administrative
  
$
798
  
$
1,034
  
Non-cash unit based compensation (included in general and administrative)
    
1,246
   
1,137
 
   
$
2,044
  
$
2,171
  

   
2006 
  
2005 
  
   
Number of Unit Appreciation
Rights 
 
Weighted
Average Exercise
Price (U.S.$) 
 
  
Number of Unit
Appreciation
Rights
 
Weighted
Average Exercise
Price
(U.S.$)
  
Year ended December 31,
                  
Outstanding, beginning of year
    
768,693
 
$
8.34
    
976,000
 
$
7.98
  
Granted
    
-
   
-
   
147,000
   
10.01
 
Exercised
    
(282,840
)
  
8.20
   
(296,641
)
  
7.91
 
Forfeited
    
(13,332
)
  
8.85
   
(57,666
)
  
8.79
 
Outstanding, end of year
    
472,521
 
$
8.41
    
768,693
 
$
8.34
  
Exerciseable, end of year
    
81,852
 
$
8.46
    
22,704
 
$
8.92
  
Weighted average remaining contract life (years)
    
1.58
         
2.58
        
Average potential reductions to exercise price
  
$
1.30
        
$
0.71
        
 
(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, 2006 there were 2,755,566 notional units outstanding under the key employee plan (2005 - 2,200,000) which vest one third three years after grant date, one third four years after grant date and one third five years after grant date. In 2006, 555,566 units were granted with the remaining 2,200,000 being granted in 2004. There were 12,984,001 notional units outstanding under the phantom unit plan (2005 - 4,155,290) of which all notional units vest immediately and are payable 90 days from the fiscal year-end. At December 31, 2006, $13.4 million (2005 - $3.5 million) is included in accounts payable and accrued liabilities for these plans, and $2.9 million (2005 - $1.8 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,
  
2006
  
2005
  
Cash general and administrative
  
$
3,807
  
$
1,255
  
Non-cash unit based compensation (included in general and administrative)
    
10,478
    
4,961
  
   
$
14,285
  
$
6,216
  

13.   Income taxes

Provident follows the liability method for calculating future income taxes. Under this method, future income tax assets and liabilities are recognized based on the estimated tax effects of temporary differences in the carrying value of assets and liabilities, reported in the financial statements of the corporate subsidiaries, and their respective tax bases, using income tax rates substantively enacted on the consolidated balance sheet date:
   
Year ended December 31,
  
   
2006
  
2005
  
Petroleum and natural gas properties, production facilities and other
  
$
266,156
  
$
89,607
  
Midstream facilities
    
42,850
    
1,988
  
   
$
309,006
  
$
91,595
  

The income tax provision differs from the expected amount calculated by applying the Canadian combined federal and provincial income tax rate of 34.67 percent (2005 - 37.82 percent) as follows:

   
Year ended December 31,
  
   
2006
  
2005
  
Expected income tax expense
  
$
40,736
  
$
48,218
  
Increase (decrease) resulting from:
              
Non-deductible Crown charges and other payments
    
8,135
    
14,285
  
Federal resource allowance
    
(5,742
)
  
(11,489
)
Alberta Royalty Tax Credit
    
(173
)
  
(188
)
Income of the Trust and other
    
(70,999
)
  
(32,567
)
Capital Taxes
    
1,314
    
4,780
  
Witholding tax and other
    
3,308
    
5,628
  
Income tax rate changes
    
(3,752
)
  
(466
)
Income tax (recovery) expense
  
$
(27,173
)
$
28,201
  

On December 21, 2006, the Minister of Finance released for comment draft legislation concerning the taxation of certain publicly traded trusts and partnerships. The legislation reflects proposals originally announced by the Minister on October 31, 2006. Under the proposed legislation, certain distributions will not be deductible to publicly traded income trusts and partnerships with the exception of real estate investments trusts and, as a result, these entities will in effect be taxed as corporations on the amount of the non-deductible distributions. For entities in existence on October 31, 2006 the proposed rules, if passed into law, would not apply until 2011. As the tax proposals had not been substantially enacted as of December 31, 2006, the consolidated financial statements do not reflect the impact of the proposed taxation.

14.   Financial instruments and hedging

Financial instruments of the Trust carried on the consolidated balance sheet consist mainly of cash and cash equivalents, accounts receivable, reclamation fund investments, current liabilities, asset retirement obligations, commodity and foreign currency contracts and long-term debt. Except as noted below, as at December 31, 2006 and 2005, 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.

-18-
 
 
(i)  
Commodity price
 
a)  
Crude oil
 
 
In 2006, Provident paid $5.7 million to settle various oil market based contracts on an aggregate volume of 2.1 million barrels. For 2005, Provident paid $59.0 million to settle various oil market based contracts on an aggregate volume of 2.6 million barrels. The estimated value of contracts in place if settled at market prices at December 31, 2006 would have resulted in an opportunity gain of $7.2 million (2005 - an opportunity cost of $7.1 million).
 
b)  
Natural Gas
 
 
In 2006, Provident received $7.6 million to settle various natural gas market based contracts on an aggregate of 9.5 million gigajoules (“GJ”). For 2005, Provident paid $5.6 million to settle various natural gas market based contracts on an aggregate of 5.2 million gigajoules (“GJ”). The estimated value of contracts in place if settled at market prices at December 31, 2006 would have resulted in an opportunity gain of $8.6 million (2005 - an opportunity cost of $6.5 million).
 
c)  
Midstream
 
 
In 2006, Provident paid $15.4 million (2005 - $2.3 million) to settle various midstream contracts, that were entered into to fix prices on product sales. The estimated value of contracts in place if settled at market prices as December 31, 2006 would have resulted in an opportunity cost of $68.8 million (2005 - $0.4 million).
 
(ii)  
Foreign exchange contracts
 
 
The estimated value of contracts in place if settled at foreign exchange rates at December 31, 2006 would have resulted in an opportunity gain of $0.1 million (2005 - opportunity cost of $0.1 million). The foreign exchange gains have been included in note 17 as a component of foreign exchange gain and other and allocated to their respective business segments.
 
The contracts in place at December 31, 2006 are summarized in the following tables:

COGP
          
 
Volume
    
Year                                Product
 
  
Terms
Effective Period
 
(Buy) 
 Sell
      
2007                            Crude Oil
750
Bpd
  
Participating Swap US $60.00 per bbl (62% above the floor price)
January 1 - December 31
 
750
Bpd
  
Puts US $60.00 per bbl
January 1 - December 31
                        Natural Gas
2,500
Gjpd
  
Participating Swap Cdn $6.50 per gj (65% above the floor price)
January 1 - August 31
 
2,000
Gjpd
  
Participating Swap Cdn $6.50 per gj (max to 100% above the floor price)
January 1 - August 31
 
5,000
Gjpd
  
Participating Swap Cdn $7.00 per gj (max to 82% above the floor price)
January 1 - March 31
 
1,500
Gjpd
  
Participating Swap Cdn $7.00 per gj (max to 80% above the floor price)
January 1 - March 31,
   
 
    
November 1 - December 31
 
4,000
Gjpd
  
Participating Swap Cdn $6.44 per gj (max to 100% above the floor price)
April 1 - August 31
 
1,500
Gjpd
  
Participating Swap Cdn $6.50 per gj (max to 61% above the floor price)
April 1 - August 31
 
3,000
Gjpd
  
Participating Swap Cdn $6.33 per gj (max to 100% above the floor price)
April 1 - October 31
 
3,000
Gjpd
  
Participating Swap Cdn $6.33 per gj (max to 90% above the floor price)
April 1 - October 31
 
6,000
Gjpd
  
Participating Swap Cdn $6.30 per gj (max to 95% above the floor price)
April 1 - October 31
 
2,000
Gjpd
  
Participating Swap Cdn $6.13 per gj (max to 68% above the floor price)
April 1 - October 31
 
1,000
Gjpd
  
Participating Swap Cdn $6.00 per gj (max to 66% above the floor price)
April 1 - October 31
 
6,500
Gjpd
  
Costless Collar Cdn $6.31 floor, Cdn $12.93 ceiling
January 1 - March 31
 
7,500
Gjpd
  
Costless Collar Cdn $6.42 floor, Cdn $9.63 ceiling
January 1 - August 31
 
4,000
Gjpd
  
Costless Collar Cdn $6.75 floor, Cdn $8.56 ceiling
April 1 - August 31
 
5,000
Gjpd
  
Puts Cdn $6.85 per gj
January 1 - December 31
 
2,000
Gjpd
  
Puts Cdn $6.75 per gj
January 1 - March 31
 
9,500
Gjpd
  
Puts Cdn $6.89 per gj
January 1 - March 31,
         
November 1 - December 31
 
4,000
Gjpd
  
Puts Cdn $6.75 per gj
November 1 - December 31
 
-19-
 
 
USOGP
            

 
  
   Volume
    
Year
Product
(Buy)
Sell
 
Terms
Effective Period
2007
Crude Oil
250
Bpd
US $60.00 per bbl
January 1 - December 31
   
250
Bpd
Participating Swap US $55.00 per bbl (max to 84% above the floor price)
January 1 - December 31
   
3,500
Bpd
US $67.84 per bbl
January 1 - June 30
   
2,650
Bpd
US $68.44 per bbl
July 1 - December 31
   
250
Bpd
Costless Collar US $66.00 floor, US $69.25 ceiling
July 1 - December 31
   
250
Bpd
Costless Collar US $66.00 floor, US $71.50 ceiling
July 1 - December 31
2008
Crude Oil
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
   
2,500
Bpd
Participating Swap US $60.00 per bbl (max to 53.3% above the floor price)
July 1 - September 31
   
4,500
Bpd
Participating Swap US $60.00 per bbl (avg to 56% above the floor price)
October 1 - December 31
2009
Crude Oil
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
 

Midstream
        
   
  Volume  
    
Year
Product
(Buy)
Sell 
Terms
Effective Period
           
2007
Crude Oil
250
Bpd
Costless Collar US $64.50 floor, US $69.20 ceiling
January 1 - December 31
   
2,000
Bpd
Costless Collar US $72.43 floor, US $80.29 ceiling
April 1 - December 31
   
10,077
Bpd
Cdn $77.02 per bbl
January 1 - December 31
   
(7,643)
Bpd
Cdn $64.35 per bbl (4)
January 1 - March 31
   
(1,122)
Bpd
US $80.81 per bbl (4)
January 1 - March 31
 
Natural Gas
3,000
Gjpd
Cdn $8.28 per gj
January 1 - January 31
   
(1,350)
Gjpd
Costless Collar Cdn $8.62 floor, Cdn $9.10 ceiling
January 1 - December 31
   
(3,201)
Gjpd
Cdn $7.70 per gj
January 1 - March 31
   
(22,196)
Gjpd
Cdn $8.17 per gj
April 1 - December 31
   
(48,493)
Gjpd
Cdn $8.20 per gj
January 1 - December 31
 
Propane
9,328
Bpd
US $0.9841 per gallon (4) (6)
January 1 - March 31
   
806
Bpd
US $0.965 per gallon (6) (8)
January 1 - February 28
   
1,666
Bpd
US $0.9668 per gallon (6) (8)
January 1 - March 31
   
948
Bpd
Cdn $1.2081 per gallon (4) (6)
January 1 - March 31
 
Normal Butane
1,808
Bpd
US $1.1135 per gallon (4) (7)
January 1 - March 31
   
306
Bpd
Cdn $1.3788 per gallon (4) (7)
January 1 - March 31
 
Foreign Exchange
  
 
Sell US $817,163 per month @ 1.1434 (5)
January 1 - December 31
       
Sell US $968,486 per month @ 1.1013 (5)
April 1 - December 31
           
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 $73.00 floor, US $80.00 ceiling
January 1 - June 30
   
500
Bpd
Costless Collar US $64.00 floor, US $74.50 ceiling
January 1 - September 30
   
250
Bpd
US $65.60 per bbl
January 1 - December 31
   
8,521
Bpd
Cdn $76.65 per bbl
January 1 - December 31
 
Natural Gas
(56,824)
Gjpd
Cdn $8.34 per gj
January 1 - December 31
   
(13,123)
Gjpd
Cdn $8.60 per gj
January 1 - June 30
   
(2,965)
Gjpd
Cdn $7.94 per gj
January 1 - September 30
   
(8,760)
Gjpd
Cdn $7.94 per gj
July 1 - December 31
 
Foreign Exchange
  
 
Sell US $599,652 per month @ 1.1172 (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
           
2009
Crude Oil
2,500
Bpd
Costless Collar US $65.00 floor, US $69.23 ceiling
January 1 - December 31
   
500
Bpd
Costless Collar US $70.00 floor, US $79.00 ceiling
January 1 - June 30
   
1,500
Bpd
Cdn $81.44 per bbl
January 1 - June 30
   
250
Bpd
Cdn $77.37 per bbl
January 1 - March 31
   
500
Bpd
Cdn $75.10 per bbl
July 1 - December 31
   
250
Bpd
Cdn $76.70 per bbl
July 1 - September 30
   
250
Bpd
US $64.60 per bbl
January 1 - December 31
   
3,374
Bpd
Cdn $74.26 per bbl
January 1 - December 31
 
Natural Gas
(35,261)
Gjpd
Cdn $8.28 per gj
January 1 - December 31
   
(1,481)
Gjpd
Cdn $8.74 per gj
January 1 - March 31
   
(14,714)
Gjpd
Cdn $8.32 per gj
January 1 - June 30
   
(1,481)
Gjpd
Cdn $7.59 per gj
July 1 - September 30
   
(2,776)
Gjpd
Cdn $7.75 per gj
July 1 - December 31
 
Foreign Exchange
    
Sell US $522,154 per month @ 1.1093 (5)
January 1 - December 31
       
Sell US $1,055,833 per month @ 1.099 (5)
January 1 - June 30
       
 
  
2010
Crude Oil
1,500
Bpd
Costless Collar US $62.90 floor, US $67.48 ceiling
January 1 - December 31
   
4,688
Bpd
Cdn $72.98 per bbl
January 1 - December 31
 
Natural Gas
(35,273)
Gjpd
Cdn $8.03 per gj
January 1 - December 31
   
(1,485)
Gjpd
Cdn $7.09 per gj
April 1 - December 31
 
Foreign Exchange
    
Sell US $472,828 per month @ 1.1078 (5)
January 1 - December 31
 
-20-
 
 
Midstream, continued
    
 
         
Effective Period 
   
Volume 
Terms 
  
Year 
Product 
 (Buy) 
Sell 
    
           
2011
Crude Oil
500
Bpd
Costless Collar US $65.00 floor, US $75.00 ceiling
January 1 - June 30
   
250
Bpd
Costless Collar US $60.00 floor, US $68.10 ceiling
July 1 - September 30
   
250
Bpd
Costless Collar US $60.00 floor, US $67.30 ceiling
July 1 - September 30
   
500
Bpd
Costless Collar US $56.00 floor, US $75.25 ceiling
July 1 - September 30
   
500
Bpd
Costless Collar US $58.00 floor, US $76.20 ceiling
July 1 - September 30
   
500
Bpd
Costless Collar US $60.00 floor, US $71.60 ceiling
July 1 - September 30
   
3,250
Bpd
Cdn $74.26 per bbl
January 1 - June 30
   
750
Bpd
Cdn $69.94 per bbl
January 1 - March 31
   
885
Bpd
Cdn $70.99 per bbl
January 1 - September 30
   
250
Bpd
Cdn $73.35 per bbl
January 1 - October 31
   
250
Bpd
Cdn $72.75 per bbl
January 1 - November 30
   
500
Bpd
Cdn $73.15 per bbl
April 1 - June 30
 
Natural Gas
(2,700)
Gjpd
Cdn $8.53 per gj
January 1 - March 31
   
(23,726)
Gjpd
Cdn $7.46 per gj
January 1 - June 30
   
(4,955)
Gjpd
Cdn $7.02 per gj
January 1 - September 30
   
(1,481)
Gjpd
Cdn $7.25 per gj
January 1 - October 31
   
(1,481)
Gjpd
Cdn $7.24 per gj
January 1 - November 30
   
(11,859)
Gjpd
Cdn $6.72 per gj
July 1 - September 30
   
(2,820)
Gjpd
Cdn $6.21 per gj
April 1 - June 30
 
Foreign Exchange
    
Sell US $980,417 per month @ 1.0805 (5)
January 1 - June 30
       
Sell US $717,600 per month @ 1.0931 (5)
July 1 - September 30
(1) The above table represents a number of transactions entered into over an extended period of time.
(2) Natural gas contracts are settle against AECO monthly index
(3) Crude Oil contracts are settled against NYMEX WTI calendar average
(4) Conversion of crude oil BTU hedges to propane
(5) U.S. Dollar hedge contracts settled against Bank of Canada noon rate average
(6) Propane contracts are settled against Belvieu C3 TET
(7) Normal butane contracts are settled against Belvieu NC4 NON-TET
(8) Midstream inventory hedges
 
15.    
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 $1.9 million at the beginning of 2006. For the year ended December 31, 2006, $2.7 million was contributed to the reserve and actual expenditures totaled $4.6 million. During 2006, Provident retired a number of wells that included non- routine costs. As a result, the cash reserve was depleted in the year. It is expected that the reserve will rebuild in 2007. For the year ended December 31, 2005, $2.9 million was added to the cash reserve and actual expenditures totaled $2.5 million.
 
16.    
Commitments
 
 
Provident has office lease commitments that extend through April 2013. Future minimum lease payments for the following five years are: 2007 - $4.6 million; 2008 - $8.0 million; 2009 - $7.8 million; 2010 - $6.9 million; and 2011 - $6.9 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: 2007 - U.S. $5.8 million; 2008 - U.S. $5.6 million; 2009 - U.S. $4.2 million; 2010 - U.S. $2.7 million; and 2011 - U.S. $1.5 million. dditionally, 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: 2007 - $4.5 million; 2008 - $4.3 million; 2009 - $4.0 million; 2010 - $3.8 million; and 2011 - 4.1 million. In relation to the United States oil and natural gas production segment, Provident has surety bonds to provide U.S. $4.9 million of coverage to Occidental Petroleum Corporation related to a purchase of oil and gasproducing properties.
-21-
 
 
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: 2007 - U.S. $0.7 million; 2008 - U.S. $0.6 million; 2009 - U.S. $0.6 million; 2010 - U.S. $0.6 million; and 2011 - U.S. $0.6 million.

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 services and marketing.
 
Oil and natural gas production in Canada and the United States includes exploitation, development and production of crude oil and natural gas reserves. Midstream services and marketing includes processing, extraction, transportation, loading and storage of natural gas liquids, and marketing of natural gas liquids.
 
Geographically the Trust operates in Canada and the USA in the oil and gas production business segment. The geographic components have been presented for the oil and natural gas business as well as the midstream services and marketing business that operates in both Canada and the USA.

-22-
 
       
Year ended December 31, 2006      
     
         
Canada Oil
and Natural
Gas
Production
  
United States
Oil and
Natural Gas Production
  
Total Oil and
Natural Gas Production
  
Midstream
Services and Marketing (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
 
Non-cash revenue
                                      
Unrealized gain (loss) on financial derivative
instruments
  
17,299
   
7,735
   
25,034
   
(68,348
)
  
(43,314
)
Amortization of 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
 
Non-cash unit based compensation
          
4,320
   
12,476
   
16,796
   
6,287
   
23,083
 
Internal management charge
          
(1,280
)
  
1,280
   
-
   
-
   
-
 
Gain on sale of assets
          
-
   
-
   
-
   
-
   
-
 
Capital taxes
          
1,314
   
-
   
1,314
   
-
   
1,314
 
Current and withholding taxes
          
(2,124
)
  
3,332
   
1,208
   
4,621
   
5,829
 
Future income tax (recovery) expense
  
(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 year
        
$
83,453
  
$
2,598
 
$
86,051
 
$
54,869
 
$
140,920
 
(1) Included in the Midstream Services and Marketing segment is product sales and service revenue of $332.9 million associated with U.S. operations.
 

       
December 31, 2006      
     
         
Canada Oil
and Natural
Gas
Production
  
United States
Oil and
Natural Gas Production 
  
Total Oil and
Natural Gas Production 
  
Midstream
Services and Marketing 
  
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
          
482,369
   
(2,012
)
  
480,357
   
-
   
480,357
 
Proceeds from property dispositions
          
(1,264
)
  
(4
)
  
(1,268
)
  
-
   
(1,268
)
Goodwill additions
          
-
   
-
   
-
   
2,285
   
2,285
 
Working capital
                                      
Accounts receivable
          
58,250
   
24,744
   
82,994
   
187,141
   
270,135
 
Petroleum product inventory
          
-
   
-
   
-
   
85,868
   
85,868
 
Accounts payable and accrued liabilities
          
86,305
   
52,626
   
138,931
   
156,072
   
295,003
 
Long-term debt
        
$
217,533
  
$
128,542
 
$
346,075
 
$
642,710
 
$
988,785
 
 
 
   
 Year ended December 31, 2005
  
   
Canada Oil
and
Natural
Gas
Production
  
United
States Oil
and
Natural
Gas
Production
  
Total Oil
and
Natural
Gas
Production
  
Midstream
Services and Marketing (1)
  
Total
  
Revenue
                      
Gross production revenue
  
$
466,945
  
$
154,816
  
$
621,761
  
$
-
  
$
621,761
  
Royalties
    
(95,403
)
  
(15,019
)
  
(110,422
)
  
-
   
(110,422
)
Product sales and service revenue
    
-
   
-
   
-
   
908,111
   
908,111
 
Realized loss on financial derivative instruments
    
(48,308
)
  
(16,323
)
  
(64,631
)
  
(2,229
)
  
(66,860
)
     
323,234
   
123,474
   
446,708
   
905,882
   
1,352,590
 
Expenses
                                
Cost of goods sold
    
-
   
-
   
-
   
786,564
   
786,564
 
Production, operating and maintenance
    
95,278
   
39,513
   
134,791
   
36,402
   
171,193
 
Transportation
    
5,702
   
-
   
5,702
   
1,230
   
6,932
 
Foreign exchange gain and other
    
(1,815
)
  
(504
)
  
(2,319
)
  
(569
)
  
(2,888
)
Cash general and administrative
    
18,552
   
11,490
   
30,042
   
11,566
   
41,608
 
     
117,717
   
50,499
   
168,216
   
835,193
   
1,003,409
 
Earnings before interest, taxes, depletion, depreciation, accretion and other non-cash items
    
205,517
   
72,975
   
278,492
   
70,689
   
349,181
 
Non-cash revenue
                                
Unrealized gain (loss) on non-hedging derivative instruments
    
13,302
   
(1,910
)
  
11,392
   
(1,564
)
  
9,828
 
Amortization of loss on non-hedging derivative instruments
    
(2,144
)
  
-
   
(2,144
)
  
-
   
(2,144
)
     
11,158
   
(1,910
)
  
9,248
   
(1,564
)
  
7,684
 
Other expenses
                                
Depletion, depreciation and accretion
    
155,929
   
25,553
   
181,482
   
11,754
   
193,236
 
Interest on bank debt
   
6,833
   
2,292
   
9,125
   
1,750
   
10,875
 
Interest and accretion on convertible debentures
   
12,342
   
4,141
   
16,483
   
3,160
   
19,643
 
Amortization of deferred financing charges
    
885
   
297
   
1,182
   
227
   
1,409
 
Unrealized foreign exchange gain and other
    
31
   
10
   
41
   
(397
)
  
(356
)
Non-cash unit based compensation
    
2,640
   
6,098
   
8,738
   
1,015
   
9,753
 
Internal management charge
    
(1,695
)
  
1,695
   
-
   
-
   
-
 
Gain on sale of assets
    
-
   
-
   
-
   
(5,188
)
  
(5,188
)
Capital taxes
    
4,780
   
-
   
4,780
   
-
   
4,780
 
Current and withholding taxes
    
-
   
5,628
   
5,628
   
-
   
5,628
 
Future income tax (recovery) expense
    
(560
)
  
18,320
   
17,760
   
33
   
17,793
 
     
181,185
   
64,034
   
245,219
   
12,354
   
257,573
 
Non-controlling interest - USOGP
    
-
   
1,596
   
1,596
   
-
   
1,596
 
Non-controlling interest - Exchangeables
    
138
   
13
   
151
   
619
   
770
 
Net income for the year
  
$
35,352
  
$
5,422
  
$
40,774
  
$
56,152
  
$
96,926
  
(1) Included in the Midstream Services and Marketing segment is product sales and service revenue of $19.7 million associated with U.S. operations.
 
       
December 31, 2005
          
       
United
              
   
Canada Oil
  
States Oil
  
Total Oil
          
   
and
  
and
  
and
  
Midstream
      
   
Natural
  
Natural
  
Natural
  
Services
      
   
Gas
  
Gas
  
Gas
  
and
      
   
Production
  
Production
  
Production
  
Marketing
  
Total
  
Selected balance sheet items
                                
Capital Assets
                                
Property, plant and equipment net
  
$
634,732
  
$
351,073
  
$
985,805
  
$
716,844
  
$
1,702,649
  
Intangible assets
    
-
    
-
    
-
    
215,850
    
215,850
  
Goodwill
    
330,944
    
-
    
330,944
    
98,124
    
429,068
  
Capital Expenditures
                                
Property, plant and equipment net
    
85,402
    
52,897
    
138,299
    
18,200
    
156,499
  
Corporate acquisitions
    
-
    
91,420
    
91,420
    
772,303
    
863,723
  
Oil and gas property acquisitions
    
586
    
-
    
586
    
-
    
586
  
Proceeds from property dispositions
    
45,100
    
-
    
45,100
    
-
    
45,100
  
Goodwill additions
    
-
    
-
    
-
    
98,124
    
98,124
  
Working capital
                                
Accounts receivable
    
135,220
    
22,310
    
157,530
    
109,716
    
267,246
  
Petroleum product inventory
    
-
    
-
    
-
    
110,638
    
110,638
  
Accounts payable and accrued liabilities
    
176,628
    
43,243
    
219,871
    
89,833
    
309,704
  
Long-term debt
  
$
238,843
  
$
168,075
  
$
406,918
  
$
477,686
  
$
884,604
  
 
-26-
 
 
18.    Reconciliation of financial statements to United States generally accepted accounting principles
 

The consolidated financial statements have been prepared in accordance with accounting principles generally accepted in Canada (“Canadian GAAP”). Any differences in accounting principles as they pertain to the accompanying financial statements are not material except as described below. All adjustments are measurement differences. Disclosure items are not noted.

Consolidated Statements of Earnings - U.S. GAAP
                 
                   
For the year ending December 31,
           
 2006
  
 2005
  
(Cdn$000s)
                          
Net income as reported
              
$
140,920
  
$
96,926
  
Adjustments
                          
Depletion, depreciation and accretion (a)
                
12,146
    
13,697
  
Depletion, depreciation and accretion other (a)
                
(382,230
)
  
-
  
FAS 133 adjustment (b)
                
-
    
2,144
  
General and administrative (e)
                
(483
)
  
(1
)
Future income recovery (taxes) (a) (b) (c)
                
110,898
    
(5,357
)
Accretion on convertible debentures (g)
                
2,694
    
2,849
  
Non-controlling interest - Exchangeable shares (i)
                
754
    
770
  
Net (loss) income - U.S. GAAP
              
$
(115,301
)
$
111,028
  
Net (loss) income per unit - basic and diluted
              
$
(0.59
)
$
0.70
  
                           
                           
Condensed Consolidated Balance Sheet
                          
As at December 31 (Cdn$ 000s)
    
2006
      
2005
    
 
    
Canadian
    
U.S. GAAP
    
Canadian GAAP
    
U.S. GAAP
  
Assets
                          
Property, plant and equipment (a)
  
$
2,333,537
  
$
1,906,964
  
$
1,702,689
  
$
1,646,200
  
Liabilities and unitholders’ equity
                          
Long-term debt - convertible debentures (g)
    
285,792
    
300,110
    
298,007
    
315,486
  
Other long-term liabilities (e)
    
16,305
    
16,788
    
5,019
    
5,019
  
Future income taxes (a) (b) (c)
    
309,006
    
180,122
    
91,595
    
73,609
  
Non-controlling interest - Exchangeable shares (i)
    
-
    
-
    
8,259
    
-
  
Units subject to redemption (h) (i)
    
-
    
2,317,196
    
-
    
2,236,360
  
Convertible debentures equity component (g)
    
18,522
    
-
    
19,301
    
-
  
Unitholders’ contributions (h)
    
2,254,048
    
-
    
1,971,707
    
-
  
Cumulative translation adjustment (f)
    
(42,294
)
  
-
    
(41,785
)
  
-
  
Accumulated income (loss)
    
238,208
    
(1,044,840
)
  
97,288
    
(838,253
)
Accumulated cash distributions (h)
    
(926,825
)
  
-
    
(643,360
)
  
-
  
Accumulated other comprehensive loss (f)
  
$
-
  
$
(43,187
)
$
-
  
$
(42,679
)

(a)  
Under the Canadian cost recovery ceiling test the recoverability of a cost centre is tested by comparing the carrying value of the cost centre to the sum of the undiscounted proved reserve cash flows expected from the cost centre using future price estimates. If the carrying value is not recoverable, the cost centre is written down to its fair value determined by comparing the future cash flows from the proved plus probable reserves discounted at the Trust’s risk free interest rate. Any excess carrying value of the assets on the balance sheet above fair value would be recorded in depletion, depreciation and accretion expense as a permanent impairment. Under U.S. GAAP, companies utilizing the full cost method of accounting for oil and natural gas activities perform a ceiling test on each cost centre using discounted future net revenue from proved oil and natural gas reserves discounted at 10 percent.
 
Prices used in the U.S. GAAP ceiling tests are those in effect at year-end and financing and administrative expenses are excluded from the calculation. The amounts recorded for depletion and 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.
 
-27-
 
 
 
In computing its consolidated net earnings for U.S. GAAP purposes, the Trust recorded additional depletion in 2006 of $382.2 million (2005 - nil) and a related future income tax recovery of $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)  
At January 1, 2004, the Trust recorded an unrealized loss of $25.1 million in deferred charges on the consolidated balance sheet that was recognized in income over the term of the previously designated hedged items. For the period ending December 31, 2006, no expenses were recorded (2005 - $2.1 million). Under U.S. GAAP the amortization of the deferred charge has already been captured in prior period accumulated losses.
 
(c)  
The Canadian liability method of accounting for income taxes is similar to the United States FAS 109, Accounting for Income Taxes, which requires the recognition of deferred tax assets and liabilities for the expected future tax consequences of events that have been recognized in Provident’s financial statements or tax returns. Pursuant to U.S. GAAP, enacted tax rates are used to calculate future taxes, whereas Canadian GAAP uses substantively enacted rates.
 
(d)  
The consolidated statements of cash flows and operations and accumulated income are prepared in accordance with Canadian GAAP and conform in all material respects with U.S. GAAP except for the following;
(i)  
Canadian GAAP allows for the presentation of operating cash flow before changes in non-cash
 
working capital items in the consolidated statement of cash flows. This total cannot be presented under U.S. GAAP.
(ii)  
U.S. GAAP requires disclosure on the consolidated statement of operations when depreciation,
 
depletion and amortization are excluded from cost of goods sold. This disclosure has not been noted on the face of the consolidated statement of operations.
 
(e)  
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 remeasured at each reporting date until the date of settlement. Under U.S.
 
GAAP, Provident measures the fair value of such liability awards using a binomial option pricing model 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.
 
(f)  
U.S. GAAP requires gains or losses arising from the translation of self-sustaining operations to be included in other comprehensive losses. Canadian GAAP requires these amounts to be recorded in unitholders’ equity.
 
(g)  
Under Canadian GAAP Provident applies CICA Handbook Section 3861 ("HB 3861") "Financial Instruments - Presentation and Disclosure" for financial instruments that may be settled at the issuer's option in cash or its own equity. 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.
 
(h)  
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 are charged to accumulated earnings. Under Canadian GAAP, such equity instruments are considered to be permanent equity and are presented as unitholder’s equity. The Trust’s units and exchangeable shares both have a redemption feature, which qualify them to be considered under this guidance.
 
-28-
 
 
(i)  
Under Canadian GAAP, the Trust’s exchangeable shares were classified as non-controlling interest. As these exchangeable shares could be converted into trust units at the option of the holder, the exchangeable shares were classified as units subject to redemption along with the trust units for U.S.
 
GAAP purposes. In 2006, all of the outstanding exchangeable shares were converted into Provident Trust units

Recent U.S. Accounting Pronouncements
 
Accounting for certain hybrid financial instruments

In March 2006 the FASB issued FAS 155, “Accounting for Certain Hybrid Financial Instruments”. FAS 155 permits fair value re-measurement for any hybrid financial instrument that contains an embedded derivative that otherwise would require bifurcation, clarifies which interest-only and principal-only strips are not subject to FAS 133, establishes a requirement to evaluate interests in securitized financial assets to identify freestanding derivatives or instruments that are considered hybrid financial instruments, clarifies that concentrations of credit risk in the form of subordination are not embedded derivatives and eliminates the prohibition on qualifying special-purpose entities holding a derivative financial instrument that pertains to a beneficial interest other than another derivative financial instrument. This statement is effective for all financial derivative instruments acquired after September 13, 2006. The adoption of this statement has not had a material impact on the Trust’s consolidated financial statements.

Accounting for servicing of financial assets

In March 2006, FAS 156, “Accounting for Services of Financial Assets” was issued as an amendment to FAS 140. The revisions clarify when a servicer should separately recognize servicing assets and servicing liabilities, indicates that separately recognized servicing assets and liabilities should initially be measured at fair value and allows for subsequent measurement of the assets and liabilities to be conducted under the amortization method or the fair value measurement method. FAS 156 is effective for fiscal years beginning after September 15, 2006. The Trust does not expect the adoption of this statement to have a material impact on its financial statements.

Accounting for uncertainty in income taxes

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 Trust is currently evaluating the effect that this interpretation might have on the Trust’s financial statements.
 
Accounting for conditional asset retirement obligations
 
In 2005, FASB issued Financial Interpretation 47 “Accounting for Conditional Asset Retirement Obligations”. This interpretation clarifies that the term conditional asset retirement obligation as used in FAS 143 “Accounting for Asset Retirement Obligations” refers to a legal obligation to perform an asset retirement activity in which the timing and/or method of settlement are conditional on a future event that may or may not be within the control of the entity. The obligation to perform the asset retirement activity is unconditional even though uncertainty exists about the timing and/or method of settlement. Thus, the timing and/or method of settlement may be conditional on a future event. Accordingly, an entity is required to recognize a liability for the fair value of a conditional asset retirement obligation if the fair value of the liability can be reasonably estimated. This interpretation is effective no later than the end of fiscal years ending after December 15, 2005. The adoption of this statement has not had a material impact on the Trust’s consolidated financial statements.

-29-
 
 
Accounting changes and error corrections

In 2005, FASB issued FAS 154 “Accounting Changes and Error Corrections” which replaces APB Opinion 20. This statement changes the requirements for the accounting and reporting of a change in accounting principle. FAS 154 requires retrospective application of voluntary changes in accounting principles to prior period financial statements, unless it is impracticable to do so. The statement is effective for fiscal years beginning after December 15, 2005. The adoption of this statement has not had a material impact on the Trust’s financial statements.

Exchange of non-monetary assets

In 2004, FASB issued FAS 153 “Exchange of Non-monetary Assets”. This statement is an amendment of APB Opinion No. 29 “Accounting for Non-monetary Transactions”. Based on the guidance in APB Opinion No. 29, exchanges on non-monetary assets are to be measured based on the fair value of the assets exchanged. Furthermore, APB Opinion No. 29 previously allowed for certain exceptions to this fair value principle. FAS 153 eliminates APB Opinion No. 29’s exception to fair value for non-monetary exchanges of similar productive assets and replaces this with a general exception for exchange of non-monetary assets that do not have commercial substance. For purposes of this statement, a non-monetary exchange is defined as having commercial substance when the future cash flows of an entity are expected to change significantly as a result of the exchange. The provisions of this statement are effective for non-monetary asset exchanges that occur in fiscal periods beginning after June 15, 2005 and are to be applied prospectively. Earlier application is permitted for non-monetary asset exchanges that occur in fiscal periods beginning after the issue date of this statement. The adoption of this statement has not had a material impact on the Trust’s financial statements.
 
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 29, 2007.
 
     
 
        PROVIDENT ENERGY TRUST 
        By: Provident Energy Ltd.
 
 		  
 		  
Date: March 28, 2007  By:   /s/ Thomas W. Buchanan
 
Name: Thomas W. Buchanan
  Title: President and Chief Executive Officer
EXHIBIT INDEX