U.S.
SECURITIES AND EXCHANGE COMMISSION


Washington,
D.C.  20549




FORM
40-F




(Check
One)




[   ]
Registration statement pursuant to Section 12 of the Securities Exchange Act of
1934




or




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




For the
fiscal year ended December 31, 2009




Commission
file number 1-15196






PROVIDENT
ENERGY TRUST


(Exact
name of registrant as specified in its charter)




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





Suite
2100, 250 – 2nd
Street S.W., Calgary, Alberta, Canada  T2P 0C1




(403)
296-2233




(Address
and Telephone Number of Registrant’s Principal Executive Offices)




CT
Corporation System


111
Eighth Avenue


New
York, NY   10011


Phone:  (212)
894-8940





(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:




[X]
      Annual Information Form
            [X]
      Audited Annual Financial Statements


Indicate
the number of outstanding shares of each of the issuer’s classes of capital or
common stock as of the close of the period covered by the annual
report.




Trust
Units outstanding at December 31, 2009:  264,001,588




Indicate
by check mark whether the registrant: (1) has filed all reports required to be
filed by Section 13 or 15(d) of the Securities Exchange Act of 1934, as amended
(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.




YesX                                No___




Indicate
by check mark whether the registrant has submitted electronically and posted on
its corporate Web site, if any, every Interactive Data File required to be
submitted and posted pursuant to Rule 405 of Regulation S-T







(s.232.405
of this chapter) during the preceding 12 months (or for such shorter period that
the Registrant was required to submit and post such files).




Yes                                No









FORM
      40-F




Principal
      Documents


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


(a)
            Annual
      Information Form for the fiscal year ended December 31,
    2009;




(b)
            Management’s
      Discussion and Analysis of Financial Condition and Results of Operations
      for the fiscal year ended December 31, 2009;
and




(c)
            Consolidated
      Financial Statements for the fiscal year ended December 31, 2009 (Note 21 to the Consolidated
      Financial Statements relates to United States Accounting Principles and
      Reporting (U.S. GAAP)).




























ANNUAL
INFORMATION FORM




For the
year ended December 31, 2009

















March 18,
2010







TABLE
OF CONTENTS




GLOSSARY
      OF TERMS
              1ABBREVIATIONS,
      TERMS AND CONVERSIONS
              4PRESENTATION
      OF OIL AND GAS RESERVES AND PRODUCTION INFORMATION
              4NON-GAAP
      MEASURES
              5NOTE
      REGARDING FORWARD-LOOKING INFORMATION
              5INCORPORATION
      AND STRUCTURE
              8Provident
      Energy Trust
              8Provident
      Energy Ltd
              8Provident
      Midstream Holdings LP
              8Provident
      Midstream LP
              9Provident
      Midstream Inc
              9Pro
      Holding Company
              9Provident
      Energy Resources Inc
              9Provident
      Acquisitions LP
              9INTERCORPORATE
      RELATIONSHIPS
              10INFORMATION
      CONCERNING THE TRUST, PEL, PMHLP, PERI AND OTHER ENTITIES
              10Provident
      Energy Trust
              10Provident
      Energy Ltd
              18Provident
      Midstream Holdings LP
              19Provident
      Midstream LP
              20Provident
      Midstream Inc
              20Pro
      Holding Company
              20Provident
      Energy Resources Inc
              20Provident
      Acquisitions LP
              20GENERAL
      DEVELOPMENT OF THE BUSINESS OF PROVIDENT
              21RISK
      MANAGEMENT
              24OIL
      AND NATURAL GAS OPERATIONS
              24NATURAL
      GAS LIQUIDS MIDSTREAM PROCESSING AND MARKETING OPERATIONS
              24MARKET
      FOR SECURITIES
              27RECORD
      OF CASH DISTRIBUTIONS
              28PREMIUM
      DISTRIBUTION, DISTRIBUTION REINVESTMENT AND OPTIONAL UNIT PURCHASE
      PLAN
              29DIRECTORS
      AND OFFICERS
              30AUDIT
      COMMITTEE INFORMATION
              35INFORMATION
      CONCERNING THE OIL AND GAS INDUSTRY
              38INFORMATION
      CONCERNING THE NATURAL GAS LIQUIDS MIDSTREAM, PROCESSING AND MARKETING
      INDUSTRY
              42General
              42NGL
      Extraction
              42NGL
      Fractionation
              42NGL
      Transportation
              43NGL
      Storage
              43NGL
      Marketing
              43Commercial
      Arrangements
              43RISK
      FACTORS
              44Oil
      and Gas Production Risk Factors
              44Natural
      Gas Liquids Midstream Processing and Marketing Business Risk
      Factors
              49General
      Risk Factors
              51INTERESTS
      OF MANAGEMENT AND OTHERS IN MATERIAL TRANSACTIONS
              54TRANSFER
      AGENT AND REGISTRAR
              55INTERESTS
      OF EXPERTS
              55MATERIAL
      CONTRACTS
              55DOCUMENTS
      INCORPORATED BY REFERENCE
              55PRINCIPAL
      HOLDERS OF TRUST UNITS
              56ADDITIONAL
      INFORMATION
              56




SCHEDULE
A - AUDIT COMMITTEE INFORMATION





- i
-





GLOSSARY
OF TERMS




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




"ABCA" means the Business Corporations Act
R.S.A. 2000, c. B-9, as amended, including the regulations promulgated
thereunder;




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




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




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




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




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




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




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




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




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




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




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




"Midstream Business" means the
midstream business of Provident and its subsidiaries including the Midstream NGL
Business and the business carried on with the Redwater Midstream NGL
Assets;




"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
liquids midstream 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;




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




"NYSE" means the New York Stock
Exchange;







- 1
-





"PALP" means Provident
Acquisitions L.P.;




"PEL" means Provident Energy
Ltd.;




"PERI" means Provident Energy
Resources Inc.;




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




"PHC" means Pro Holding
Company;




"PMHLP" means Provident
Midstream Holdings LP;




"PMLP" means Provident
Midstream LP;




"PMI" means Provident Midstream
Inc.;




"Provident" means the Trust
and, where the context requires, includes PEL, PERI, PMHLP and the other direct
and indirect subsidiaries and affiliates of the Trust;




"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;




"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 PEL 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;







- 2
-





"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;




"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, R.S.C. 1985,
c.1, 5th Supplement and the regulations promulgated thereunder, each 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
PEL held by the Trust; and (h) all income, interest, profit, gains and
accretions and additional assets, rights and benefits of any kind or nature
whatsoever arising directly or indirectly from or in connection with or accruing
to such foregoing property or such proceeds of disposition;




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




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




"TSX" means the Toronto Stock
Exchange;




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




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




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







- 3
-








ABBREVIATIONS,
TERMS AND CONVERSIONS




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




Oil and Natural Gas
      Liquids
            
            Natural Gasbbls
            barrels
            mcf
            thousand
      cubic feetbpd
            barrels
      of oil per day
            mcfd
            thousand
      cubic feet per daymmbbls
            million
      barrels
            mmcfd
            million
      cubic feet per daymmboe
            million
      barrels of oil equivalent
            bcfd
            billion
      cubic feet per dayNGLs
            natural
      gas liquids
            mmbtu
            million
      British Thermal Unitsgj
            gigajouleOtherboe
            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.




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
      Bymcf
            cubic
      metres
            0.0282cubic
      metres
            cubic
      feet
            35.494bbls
            cubic
      metres
            0.159cubic
      metres
            bbls
            6.289feet
            metres
            0.305metres
            feet
            3.281miles
            kilometres
            1.609kilometres
            miles
            0.621acres
            hectares
            0.405hectares
            acres
            2.471gigajoules
            mmbtu
            0.950bbls
            U.S.
      gallons
            42




PRESENTATION
OF OIL AND GAS RESERVES AND PRODUCTION INFORMATION




All oil
and natural gas reserve information contained or incorporated by reference in
this Annual Information Form has been prepared and presented in accordance with
National Instrument 51-101 Standards 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. Provident 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.







- 4
-





The
preparation of oil and natural gas reserve information in accordance with NI
51-101 differs from the reserve disclosure requirements and practices in the
United States.  The primary differences between the current U.S.
requirements and the NI 51-101 requirements are that: (i) U.S. standards require
disclosure only of proved reserves, whereas NI 51-101 requires disclosure of
proved and probable reserves; and (ii) U.S. standards require that the reserves
and related future net revenue be estimated using a historic constant price,
whereas NI 51-101 requires disclosure of reserves and related future net revenue
using forecast prices.  The definitions of proved reserves also
differ, but according to the Canadian Oil and Gas Evaluation Handbook, the
reference source for the definition of proved reserves under NI 51-101,
differences in the estimated proved reserves quantities based on constant prices
should not be material.




NON-GAAP
MEASURES




In this
Annual Information Form, the Trust uses the terms "cash flow" and "funds flow
from operations" to refer to the cash available for debt repayments, capital
programs and distribution to Unitholders and as indicators of financial
performance.  "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" 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" 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" and "funds flow from
operations" are based on cash provided by operating activities before changes in
non-cash working capital related to operating activities and site restoration
expenditures, as presented in the consolidated financial statements of the
Trust.  The actual
amount of cash that is distributed cannot be assured and future distributions
may vary.  Management also uses adjusted EBITDA (as defined
below) to analyze the operating performance of the Midstream business
unit.  Adjusted 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. adjusted 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
adjusted EBITDA throughout this Annual Information Form are based on earnings
before interest, taxes, depletion, depreciation, accretion, and other non-cash
items ("adjusted EBITDA"). The Trust uses such terms as an indicator of
financial performance because such terms are commonly utilized by investors to
evaluate royalty trusts and income funds in the energy sector.  The
Trust believes that such terms are useful supplemental measures as they provide
investors with information of what cash is available for distribution from the
Trust to Unitholders in such periods.






NOTE
REGARDING FORWARD-LOOKING INFORMATION




This
Annual Information Form and the documents incorporated by reference herein
contain forward-looking information under applicable securities legislation.
This information relates to future events or the Trust's future
performance.  Such forward-looking information is provided for the
purpose of providing information about management's current expectations and
plans relating to the future.  Readers are cautioned that reliance on
such information may not be appropriate for other purposes, such as making
investment decisions.  All statements other than statements of
historical fact are forward-looking information.  In some cases,
forward-looking information can be identified by terminology such as "may",
"will", "should", "expect", "plan", "anticipate", "believe", "estimate",
"predict", "potential", "continue", or the negative of these terms or other
comparable terminology.  Statements relating to "reserves" or
"resources" are deemed to be forward-looking information, as they involve the
implied assessment, based on certain estimates and assumptions, that the
reserves and resources described can be profitably produced in the
future.







- 5
-





Forward-looking
information in this Annual Information Form includes, but is 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 midstream, NGL processing and marketing
business.  Forward-looking information is based on current
expectations, estimates and projections that involve a number of risks and
uncertainties which could cause actual events or results to differ materially
from those anticipated by the Trust and described in the forward-looking
information.  In addition, this Annual Information Form and the
documents incorporated by reference herein may contain forward-looking
information attributed to third party industry sources.  Undue
reliance should not be placed on forward-looking information, as there can be no
assurance that the plans, intentions or expectations upon which they are based
will occur.  By its nature, forward-looking information involves
numerous assumptions, known and unknown risks and uncertainties, both general
and specific, that contribute to the possibility that the predictions,
forecasts, projections and other forward-looking information will not
occur.  Forward-looking information in this Annual Information Form
and the documents incorporated by reference herein may include, but is not
limited to, information with respect to:




·
            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 an appropriate level of monthly cash
      distributions;


·
            the
      impact of Canadian governmental regulation on
  Provident;


·
            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 financial derivative
instruments;


·
            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 midstream, NGL processing and
      marketing business;


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


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




Although
the Trust believes that the expectations reflected in the forward-looking
information 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
information.  Some of the risks and other factors, some of which are
beyond the Trust's control, which could cause results to differ materially from
those expressed in the forward-looking information contained in this Annual
Information Form and the documents incorporated by reference herein include, but
are not limited to:







- 6
-





·
            general
      economic and credit 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
      legislation taxing trust income;


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


·
            fluctuation
      in foreign exchange or interest
rates;


·
            stock
      market volatility and market
valuations;


·
            the
      impact of environmental events;


·
            the
      need to obtain required approvals from regulatory
    authorities;


·
            unanticipated
      operating events which can reduce production or cause production to be
      shut-in or delayed; ·
            failure to realize the anticipated benefits of
      acquisitions;


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


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


·
            risks
      associated with foreign ownership;


·
            third
      party performance of obligations under contractual arrangements;
      and


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




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




·
            future
      natural gas and crude oil prices;


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


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


·
            the
      impact of increasing competition;


·
            Provident's
      ability to obtain financing on acceptable
terms;


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


·
            the
      timely receipt of any required regulatory
  approvals;


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


·
            field
      production rates and decline rates;


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


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


·
            currency,
      exchange and interest rates; and


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







- 7
-




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







INCORPORATION
AND STRUCTURE




Provident
Energy Trust




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




Provident
Energy Ltd.




Provident
Energy Ltd. is a corporation the common shares of which are wholly-owned by the
Trust.  PEL manages the Trust and manages and administers the
businesses of the Trust's subsidiaries.  PEL was incorporated under
the ABCA on January 19, 2001 and was amalgamated with Founders pursuant to a
plan of arrangement involving the Trust, PEL and Founders effective March 6,
2001.  PEL subsequently amalgamated with Maxx Petroleum Ltd. ("Maxx")
effective May 25, 2001 pursuant to a plan of arrangement involving the Trust,
PEL and Maxx.  PEL was also amalgamated with Richland Petroleum
Corporation ("Richland") effective January 16, 2002 pursuant to a plan of
arrangement involving the Trust, PEL and Richland.  PEL was
amalgamated with Provident Management Corporation pursuant to a management
internalization transaction involving the Trust, PEL, Provident Management
Corporation and its shareholders effective January 17, 2003.  PEL was
also amalgamated with Olympia Energy Inc. and Viracocha Energy Inc. on June 1,
2004 pursuant to plans of arrangement involving the Trust, PEL, Viracocha Energy
Inc. and Olympia Energy Inc.  PEL also amalgamated with Provident
Acquisitions Inc. on January 1, 2010 pursuant to an internal reorganization
carried out to segregate and consolidate the Trust's subsidiaries along business
lines.  The head and principal offices of PEL are located at 2100, 250
- 2nd
Street S.W., Calgary, Alberta T2P 0C1.  The registered office of PEL
is located at 3700, 400 - 3rd Avenue S.W., Calgary, Alberta T2P
4H2.




Provident
Midstream Holdings LP




Provident
Midstream Holdings LP is a limited partnership registered in the Province of
Alberta.  PMHLP was formed pursuant to a limited partnership agreement
dated September 30, 2008.  PMHLP directly and indirectly holds
substantially all of the equity interests in the subsidiaries of the Trust which
hold the Midstream Business, including PMLP and PMI.  The general
partner of PMHLP is Provident Midstream Holdings GP ULC, a wholly-owned
subsidiary of the Trust, which holds a 0.1% interest in the limited
partnership.  The Trust is the limited partner of PMHLP with a 99.9%
interest in the limited partnership.  The head and principal office of
PMHLP are located at 2100, 250 - 2nd
Street S.W., Calgary, Alberta T2P 0C1.  The registered office of PMHLP
is located at 3700, 400 - 3rd
Avenue S.W., Calgary, Alberta T2P 4H2.







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Provident
Midstream LP




Provident
Midstream LP is a limited partnership registered in the Province of
Alberta.  PMLP was formed pursuant to a limited partnership agreement
dated December 8, 2005.  PMLP directly and indirectly holds the
Canadian partnership interests acquired pursuant to the Midstream NGL
Acquisition.  The general partner of PMLP is Provident GP Inc. which
holds a 0.1 percent interest in the partnership.  PMHLP and PMI are
the limited partners of PMLP with a 99.9 percent total interest in the
partnership.  PMLP 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 PMLP are located at 2100, 250 - 2nd
Street S.W., Calgary, Alberta T2P 0C1.  The registered office of PMLP
is located at 3700, 400 - 3rd Avenue S.W., Calgary, Alberta T2P
4H2.




Provident
Midstream Inc.




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




Pro
Holding Company




Pro
Holding Company is a corporation owned by PMHLP (common shares) and PEL
(preferred shares).  PHC was incorporated in the State of Delaware on
June 7, 2004.  PHC 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 the common shares of
PMI.  The head and principal offices of PHC are located at 654 N Sam
Houston Pkwy E. Houston, Texas 77060-5919.  The registered office of
PHC is located at 2711 Centerville Road, Suite 400, Wilmington, New Castle
County, Delaware 19808.




Provident
Energy Resources Inc.




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




Provident
Acquisitions LP




Provident
Acquisitions LP is a limited partnership registered in the Province of
Alberta.  PALP was formed pursuant to a limited partnership agreement
dated April 19, 2002.  The general partner of PALP is 1398850 Alberta
Ltd., a wholly-owned subsidiary of PERI, which holds a 1 percent interest in
PALP.  PERI is the limited partner of PALP with a 99 percent interest
in the partnership.  The head and principal offices of PALP are
located at 2100, 250 - 2nd
Street S.W., Calgary, Alberta T2P 0C1.  The registered office of PALP
is located at 3700, 400 - 3rd Avenue S.W., Calgary, Alberta T2P
4H2.







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INTERCORPORATE
RELATIONSHIPS




The
following diagram of the Trust and its material subsidiaries describes the flow
of cash from the oil and gas properties and the midstream, NGL processing and
marketing business to the Trust as of March 18, 2010.









INFORMATION
CONCERNING THE TRUST, PEL, PMHLP, PERI AND OTHER ENTITIES




Provident
Energy Trust




Cash
Flow




The Trust
indirectly holds interests in petroleum and natural gas properties and the
natural gas liquids midstream processing and marketing business through PERI,
PMHLP and various other subsidiaries.  Cash flow from the petroleum
and natural gas properties flows from PERI and certain other subsidiaries to the
Trust by way of royalty payments and interest payments and principal repayments
on notes issued to the Trust and PEL from time to time. Cash flow from the
Midstream Business flows from PMHLP and its subsidiaries to the Trust by way of
interest payments and principal repayments on notes issued to PMHLP and by way
of partnership distributions from the subsidiaries of PMHLP to PMHLP and from
PMHLP to the Trust.  Distributable income generated by the royalty
payments, interest payments, principal repayments and partnership distributions
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 subsidiaries from time to time; (ii) acquire royalties; (iii)
temporarily hold cash and Permitted Investments for the purposes of paying the
expenses and liabilities of the Trust and paying amounts payable by the Trust in
connection with the redemption of any Trust Units and making distributions to
Unitholders; (iv) acquire or invest in Subsequent Investments; and (v) pay the
costs, fees and expenses associated with or incidental to the
foregoing.







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Cash
Distributions




The
Trustee intends to make cash distributions on or about the 15th day of each
month to Unitholders of record on the immediately preceding Distribution Record
Date in amounts comprised 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 to the Trust on notes issued by the Trust
from time to time.




The Trust
seeks to provide cash distributions, subject to, among other things,
fluctuations in the quantity of petroleum and natural gas substances produced,
prices received for that production, financial derivative 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
industry participants, operational matters and hazards related to the natural
gas liquids midstream processing and marketing business, capital expenditures,
debt servicing, operating costs, debt service charges and general and
administrative expenses as determined necessary by PEL 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.




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.  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 $1,025 per Initial 6.5 Percent Debenture 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 18, 2010,
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.  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







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-





date
specified by the Trust for redemption at a conversion price of $14.75 per Trust
Unit, subject to adjustment in certain circumstances.  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 $1,025 per Supplemental 6.5 Percent
Debenture, 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 18, 2010, there was $150.0 million aggregate
principal amount of Supplemental 6.5 Percent Debentures
outstanding.




Debt
Financing




The Trust
has entered into a credit agreement (the "Canadian Credit Facility") dated as of
May 4, 2007, as amended, among the Trust, National Bank of Canada, as
administrative agent, and a syndicate of Canadian chartered banks and other
Canadian and foreign financial institutions (the "Lenders").  Pursuant
to the Canadian Credit Facility, the Lenders have agreed to provide the Trust
with a total credit facility of $1.125 billion, comprised of a revolving term
credit facility in the principal amount of $1.105 billion (or the equivalent in
U.S. dollars) and an operating credit facility in the principal amount of $20
million (or the equivalent in U.S. dollars) for the general corporate purposes
of the Trust.  In 2009, the total credit facility was reduced by $95
million to $1.030 billion due to asset dispositions in Provident's upstream
business unit.  On March 1, 2010 the total credit facility was
reduced by a further $50 million to $980 million as a result of the sale of the
West Central Alberta operating area.  As of March 18, 2010, based on
the terms and conditions of the Canadian Credit Facility, the Trust has access
to $909 million of the total facility.  The borrowing capacity of the
Canadian Credit Facility is re-measured quarterly.




The
Canadian Credit Facility bears interest in accordance with a pricing grid based
on the Trust's debt to adjusted EBITDA multiple calculated using a rolling
twelve month adjusted EBITDA.  Based on the Trust's adjusted EBITDA
for the year ended December 31, 2009, the interest rate pursuant to the pricing
grid is Canadian bankers acceptance plus 1.00 percent.  The Canadian
Credit Facility is secured by a first fixed and floating charge debenture, a
general assignment of book debts, a negative pledge and an undertaking to
provide, if determined necessary by the Lenders, first charges over major
petroleum and natural gas reserves of Provident.




The Trust
may draw on the facility by way of Canadian prime rate loans, U.S. base rate
loans, banker’s acceptances, letters of credit or LIBOR loans.  At
December 31, 2009, $265.0 million (excluding outstanding letters of credit to
trade accounts) was drawn on the Canadian Credit Facility.




The
Canadian Credit Facility has a revolving three year term expiring on May 30,
2011 (the "Maturity Date").  The Trust 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 the
Trust 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
2008, under the terms of the credit facility, the Maturity Date was extended
from May 30, 2010 to May 30, 2011.




In
accordance with the Canadian Credit Facility, the Trust must maintain certain
financial covenants so long as any indebtedness is outstanding under the
facility and will not assume or create any mortgage, charge or encumbrance on
the assets of the Trust or certain subsidiaries other than permitted
encumbrances.  In addition, the facility contains other standard
covenants restricting the Trust's ability to incur indebtedness, dispose of
assets, enter into hedging arrangements or amend, supplement, cancel or
terminate any material term of the Trust Indenture (except for any changes that
are not adverse to the Lenders).  The Canadian Credit Facility also
prohibits distributions to the Unitholders: (i) if they are out of the ordinary
course of business; (ii) during the period commencing after a borrowing base
shortfall has occurred (as defined in the facility) and ending when such
shortfall has been eliminated; (iii) during the period commencing after a
default has occurred and ending when such default has been cured; (iv)
after





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an event
of default has occurred; (v) after the maturity date; (vi) if they would cause a
default or event of default or would impair the ability of the Trust or its
subsidiaries to fulfill its obligations under the Canadian Credit Facility or
the security provided in respect thereof; and (vii) the aggregate amount of such
distributions and payments during the preceding four fiscal quarters exceeds
cumulative available cash flow (as defined in the facility).




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




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




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 PEL 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.







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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.  See "Premium Distribution, Distribution
Reinvestment and Optional Unit Purchase Plan" in this Annual Information
Form.




Taxation
of the Trust




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




On July
14, 2008, Finance announced proposed amendments to the Tax Act including
technical amendments to clarify certain aspects of the SIFT Rules and to provide
rules to facilitate the conversion of existing SIFT trusts into corporations on
a tax-deferred basis (the "Conversion Rules").  Bill C-10, which
received Royal Assent on March 12, 2009, contained legislation implementing the
Conversion Rules.




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







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The
adverse tax consequences associated with the SIFT Rules could be realized by the
Trust sooner than January 1, 2011 if the Trust experiences growth other than
"normal growth" before then.  On December 15, 2006 Finance issued
guidelines with respect to what would be considered "normal growth" for this
purpose (the "Guidelines").  The Guidelines provide that "normal
growth" would include equity growth within certain "safe harbour" limits,
measured by reference to a SIFT trust's market capitalization as of the end of
trading on October 31, 2006 (which would include the SIFT's issued and
outstanding publicly traded trust units and not any convertible debt, options or
other interests convertible into or exchangeable for trust
units).  Those safe harbour limits are the greater of $50 million and
40 percent of a SIFT trust's October 31, 2006 market capitalization for the
period from November 1, 2006 to December 31, 2007, and the greater of $50
million and 20 percent of a SIFT trust's October 31, 2006 market capitalization
for each of calendar 2008, 2009 and 2010.  Moreover, these limits are
cumulative, so that any unused limit for a period carries over into the
subsequent period.  Additional details of the normal growth
constraints include the following:




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




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




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




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




On
December 4, 2008, Finance announced changes to the Guidelines to allow a SIFT
trust to accelerate the utilization of the SIFT trust's annual permitted
expansion amount for each of 2009 and 2010 so that any remaining amount is
available on and after December 4, 2008. This change does not alter the maximum
permitted expansion threshold for a SIFT trust, but it allows a SIFT trust to
use its normal growth room remaining as of December 4, 2008 in a single year,
rather than staging a portion of the normal growth room over the 2009 and 2010
years.




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.  The Trust's "safe harbour" equity
growth amount for the period ending December 31, 2009 was approximately $2,221
million and for calendar year 2010 is an additional approximately $555
million.  In 2007, 2008 and 2009, the Trust issued total equity
amounting to $580 million.




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.




The Trust
is evaluating the alternatives available pursuant to the Conversion Rules but
has not yet reached a conclusion as to the appropriate alternative for the
Trust.  If the Trust completes a conversion to a corporate structure,
the nature of a Unitholder's investment will change.  Provident does
not currently anticipate that the conversion from an income trust to a
corporation will create a taxable event for Canadian
Unitholders.  However, the final form, structure and steps involved in
the conversion transaction have not yet been finalized and as a result no
assurance can be given as to the Canadian and U.S. income tax consequences of
any such conversion or that the conversion will not result in a taxable
event.







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-





Subsequent
to a conversion to a corporation, Canadian individual shareholders would receive
taxable dividends eligible for the dividend tax credit. The tax impact of the
dividends may be different for shareholders depending on the jurisdiction in
which they are resident for tax purposes and whether they are holding their
investment in a taxable account or tax-deferred account.  For
Unitholders subject to U.S. federal income taxes, the taxation of qualified
dividends at capital gains rates will end at the end of 2010, after which
dividends will be taxed at ordinary U.S. federal income tax rates, unless
legislation is enacted extending the favourable treatment of qualified
dividends.  The Canadian withholding tax on dividends will be
consistent with the current treatment of trust distributions.  The
Board of Directors and management continue to evaluate options, including a
possible conversion to a corporation, to best position Provident beyond
2010.  See "Risk Factors - General Risk Factors".




Limitation
on Non-Resident Trust Unitholders




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".




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 PEL 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, PEL will take such steps as are necessary or
desirable to ensure that the Trust is not maintained primarily for the benefit
of Non-Residents.




PEL 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 PEL, 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 PEL, in its sole discretion, determines that it
is in the best interest of the Trust, PEL, 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




- 16
-





registration
of such Trust Units beneficially owned by Non-Residents or in such other manner
as PEL 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 PEL with satisfactory evidence that such Trust Units are
not beneficially owned by Non-Residents within such period, PEL 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 PEL determines, in its sole discretion, are
appropriate in the circumstances that will reduce or limit the number of Trust
Units held by Non-Residents to ensure that the Trust is not maintained primarily
for the benefit of Non-Residents.




Redemption
Right




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




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, registered education savings plans, deferred profit sharing plans,
registered disability savings plans or tax-free savings accounts.




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.





- 17
-





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.




Provident
Energy Ltd.




The
principal business of PEL is to manage and administer the operating activities
associated with the oil and gas properties and the natural gas liquids midstream
processing and marketing business. PEL currently has 464 employees, consultants
and contract operators at its head office location and in several field offices
within the operating areas of Northwest Alberta, Dixonville, West central
Alberta and Southern Alberta, and the NGL midstream facilities in Redwater and
Empress, Alberta, Sarnia, Ontario, Lynchburg, Virginia and Houston,
Texas.





- 18
-





Delegation
of Authority, Administration and Trust Governance




The board
of directors of PEL has generally been delegated the significant management
decisions of the Trust.  In particular, the Trustee has delegated to
PEL 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 PEL pursuant to the terms of the Unanimous
Shareholder Agreement.




Decision
Making




The board
of directors of PEL supervises the management of the business and affairs of the
Trust, including the business and affairs of the Trust delegated to
PEL.  In particular, significant operational decisions and all
decisions relating to: (i) the acquisition and disposition of properties
for a purchase price or proceeds in excessof 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 PEL.  In addition, the Trustee has delegated
certain matters to the board of directors of PEL 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 PEL on behalf
of the Trust.  The board of directors of PEL generally holds regularly
scheduled meetings to review the business and affairs of PEL and make any
necessary decisions relating thereto.




Common
Shares




All of
the issued and outstanding common shares of PEL are held by the Trust. Each
common share of PEL entitles its holder to receive notice of and to attend all
meetings of the shareholders of PEL and to one vote at such
meetings.  The holders of the common shares are, at the discretion of
the board of directors of PEL 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 PEL upon the liquidation, dissolution,
bankruptcy or winding-up of PEL 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 PEL.  Any decision to
pay dividends on the common shares of PEL in the future will be made by the
board of directors of PEL on the basis of PEL's earnings, financial requirements
and other conditions existing at the time.




Provident
Midstream Holdings LP
  PMHLP is
a holding partnership which directly and indirectly (through PHC) holds all of
the equity interests in PMLP and PMI, other than the interests held by PEL
through the preferred shares PEL holds in PHC.  PMHLP was formed in
September 2008 and holds, directly and indirectly, substantially all of the
equity interests in the subsidiaries of the Trust which hold the Midstream
Business.





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-





Provident
Midstream LP




PMI and
PMHLP are the limited partners of PMLP.  The general partner of PMLP
is Provident GP Inc. which is a wholly owned subsidiary of
PMHLP.  PMLP holds, either directly or indirectly through
partnerships, all of the assets located in Canadaacquired as a result of
the Midstream NGL Acquisition and the Redwater Acquisition, other than minor
general partnership interests held by Provident GP Inc., a wholly-owned
subsidiary of PMHLP.  Cash flow from these assets flows to PMHLP and
then on to the Trust by way of distributions on limited partnership
units.




Provident
Midstream Inc.




PMI holds
an interest in PMLP  The Trust receives cash flow from PMI by way of
interest and principal payments on debt owing from PMI to PMHLP which is then
distributed to the Trust by way of distributions on limited partnership
units.




Pro
Holding Company




PHC is
owned by PMHLP (common shares) and PEL (preferred shares).  PHC 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 the common shares of
PMI.




Provident
Energy Resources Inc.




PERI is a
direct wholly owned subsidiary of the Trust.  PERI is managed by
PEL.  PERI is engaged in the acquisition, exploitation, development
and production of crude oil and natural gas in the Western Canadian Sedimentary
Basin.  PERI directly and indirectly holds substantially all of the
Trust's crude oil and natural gas production assets.




Royalties




PERI 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
PERI.




PERI 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 PERI.




Notes




PERI has
issued notes to the Trust and PEL in connection with certain acquisitions and
other transactions.  Cash flow from PERI's producing properties
distributed from PERI includes interest payments and principal repayments on the
various notes held by the Trust and PEL.




Provident
Acquisitions L.P.




PALP
holds certain Southern Alberta oil and gas properties.  PERI is the
limited partner of PALP and holds a 99 percent interest in the
partnership.  The general partner of PALP is 1398850 Alberta Ltd., a
wholly-owned subsidiary of PERI, which holds a 1 percent interest in
PALP.





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GENERAL
DEVELOPMENT OF THE BUSINESS OF PROVIDENT




The
following information describes the development of the business of Provident
over the last three completed financial years.




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




On May 3,
2007, the Trust entered into an acquisition agreement with Capitol Energy
Resources Ltd.  ("Capitol") pursuant to which the Trust agreed to make
an offer to purchase all of the issued and outstanding common shares of Capitol
(the "Capitol Shares"), including Capitol Shares that became outstanding upon
exercise of options to purchase Capitol Shares.




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




On June
20, 2007, the Trust announced that PERI had acquired approximately 96.2% of the
outstanding Capitol Shares for $8.16 in cash per share. Following the expiry of
the offer, PERI acquired the remaining Capitol Shares pursuant to the compulsory
acquisition provisions of the ABCA.  The Capitol Shares were de-listed
from the TSX on June 21, 2007.  Effective June 21, 2007, PERI and
Capitol were amalgamated with the amalgamated company continuing under the name
"Provident Energy Resources Inc.".




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




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




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




On
October 22, 2007, the Trust entered into an acquisition agreement with Triwest
Energy Inc. ("Triwest") pursuant to which the Trust agreed to make an offer to
purchase all of the issued and outstanding class "A" voting common shares of
Triwest (the "Triwest Shares"), including Triwest Shares that became outstanding
upon exercise of options to purchase Triwest Shares, for 0.6539 Trust Units and
$0.1569 in cash for each Triwest Share.  Triwest was an independent
company engaged in the acquisition, exploration,
development and production of oil and natural gas in western Canada, with
operations principally conducted in Saskatchewan. 
 On
December 4, 2007, the Trust announced that PERI had acquired 9,533,279 of the
outstanding Triwest Shares, representing approximately 99.7% of the outstanding
Triwest Shares (calculated on a diluted basis), pursuant to the
offer.  PERI acquired the remaining Triwest Shares not deposited
pursuant to the







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-





offer in
accordance with the compulsory acquisition procedures of the ABCA following the
expiry time.  An aggregate of 6,251,149 Trust Units were issued and
approximately $1.5 million in cash paid in payment of all of the outstanding
Triwest Shares.




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




On
February 5, 2008, the Trust outlined the strategic initiatives it was
undertaking respecting its investment in its U.S. businesses, BreitBurn MLP and
BEC L.P.   The Trust also provided an update with respect to its
planning process initiated to facilitate business growth and performance and
access to capital.  The planning process was also in response to the
Canadian Federal Government's decision to impose growth restrictions on Canadian
energy trusts and, effective 2011, to implement a tax on income trust
distributions.  The strategic review process announced on
February 5, 2008 was undertaken with the intent to optimize business
performance, facilitate growth, improve the cost of capital, and ensure the
Trust is being accorded the appropriate value for its component
businesses.




On June
17, 2008, the Trust sold a portion of its U.S. oil and gas production business,
consisting of its 22 percent interest in BreitBurn MLP and its 96 percent
interest in BreitBurn GP LLC, for cash proceeds, net of transaction costs, of
U.S. $342.2 million.  The Trust recorded a gain on sale of $187.9
million and $127.7 million in current tax expense, related to this
transaction.  Proceeds from the sale were applied to Provident's
Canadian Credit Facility.




On August
26, 2008, the Trust closed the sale of the remaining portion of its U.S. oil and
gas production business, comprised of an approximate 96 percent interest in BEC
L.P., for total consideration of U.S. $300.4 million, consisting of cash
proceeds, net of transaction costs, of U.S. $290.4 million and a U.S. $10
million note.  The Trust recorded a gain on sale of $75.7 million and
$66.9 million in current tax expense related to this
transaction.  Proceeds from the sale were applied to Provident's
Canadian Credit Facility.




On
October 1, 2008, the Trust implemented certain internal reorganization
transactions intended to better segregate the structure of the Trust's
subsidiaries along business lines.  As a result of these transactions,
the entities which carry on the Midstream Business are now largely held by
PMHLP.




During
the strategic review process announced in February of 2008, it was determined
that the sale of the United States oil and natural gas production ("USOGP")
business was an important step in optimizing business performance, facilitating
business growth, improving overall access to and cost of capital, enhancing the
valuation of Provident's component businesses and optimizing Provident's
structure.  Following the sale of USOGP, management and the Board of
Directors evaluated the complete spectrum of strategic options available for
Provident's remaining Canadian oil and gas production and midstream business
units.  In May 2009, after an extensive review, it was determined that
in the context of the macroeconomic environment (characterized by low commodity
prices and volatility in both equity and debt markets at that time), it was in
the best interest of Unitholders that Provident remain structured as a
cash-distributing, diversified energy enterprise.  Provident also
completed an internal reorganization to improve the efficiency and
competitiveness of the businesses.  The internal reorganization was
designed to improve the focus of each business unit, improve management's line
of sight to the key performance measures in each business, and reduce general
and administrative costs.









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On August
12, 2009, Provident entered into an agreement with BP Canada to purchase an
additional 6.15 percent interest in the Sarnia fractionation facility operated
by BP Canada for an immediate payment of $14.8 million and a deferred payment of
$3.7 million for a facility enhancement planned for 2010.  The
acquisition increased the Trust's ownership in the Sarnia fractionator to
approximately 16.5 percent, enhancing propane-plus fractionation capacity in the
Empress East System by approximately 7,400 bpd to approximately 20,000 bpd in
total.




On August
24, 2009, PEL and certain of the Trust's other subsidiaries entered into an
agreement with Crescent Point Energy Corp. ("Crescent Point") to sell certain
oil and natural gas production assets located primarily in Southeast and
Southwest Saskatchewan, including interests, royalties and all associated
assets, equipment, production facilities, gathering systems, seismic and
contractual arrangements, to Crescent Point for a purchase price of $225 million
in cash, subject to normal closing adjustments.  Second quarter
production from the Southeast Saskatchewan properties averaged 2,680 barrels of
light crude oil per day and from the Southwest Saskatchewan properties was 4,346
mcfd of natural gas and 242 barrels of oil for a combined average production of
3,646 boed.  At June 30, 2009, combined proved plus probable ("P+P")
reserves for these areas equalled approximately 10.2 million boe.  The
sale of these assets reflected transaction metrics of $61,710 per flowing boed
and $22.06 per boe of P+P reserves.




On
September 30, 2009, the Trust announced that it had closed the sale of its
oil and natural gas assets in Southeast and Southwest Saskatchewan to Crescent
Point for cash consideration of $226 million including closing
adjustments.  Effective September 30, 2009, the Trust also
completed the sale of a minor property in the Lloydminster area of Alberta
(Dolcy) for $13 million.  Proceeds from both dispositions were
initially applied to Provident's Canadian Credit Facility.




On
October 28, 2009, the Trust announced it had entered into an agreement with
Emerge Oil & Gas Inc. ("Emerge"), a private oil and gas company, to sell the
Trust's oil and natural gas assets in the Lloydminster area for total
consideration of $85 million, consisting of $68 million in cash and $17 million
in equity of Emerge.  Production from these assets during the third
quarter of 2009 was 2,200 boed and was predominantly heavy oil.  P+P
reserves were approximately 4.4 million boe as of June 30, 2009.  The
sale of these assets reflected transaction metrics of $39,545 per flowing boed
and $19.77 per boe of P+P reserves.  The Trust completed the sale of
these assets on November 30, 2009.  Proceeds from the sale were
initially applied to Provident's Canadian Credit Facility.




On
November 25, 2009, the Trust announced that it had entered into an agreement
with Dow Chemical Canada to purchase a commercial storage facility in Corunna,
Ontario.  Located in close proximity to the Trust's Sarnia operations,
the 1,000 acre site has an active cavern storage capacity of 12.1 mmbbls,
consisting of 5.0 mmbbls of hydrocarbon storage and 7.1 mmbbls currently used
for brine storage.  In addition, the facility has 13 pipeline
connections and a small rail offloading facility.  The acquisition is
expected to close by the end of the second quarter of 2010.




On
December 23, 2009, the Trust entered into an agreement with Storm Ventures
International Inc., a private oil and gas company, to sell oil and natural gas
assets in West Central Alberta for cash consideration of $190 million, prior to
normal closing adjustments.  The West Central Alberta operating area
produces approximately 5,000 boed, comprised of approximately 70 percent natural
gas and 30 percent liquids.  Total proved reserves were 10.5 mmboe at
September 30, 2009, while P+P reserves were approximately 14.6
mmboe.  The sale reflects transaction metrics of $38,000 per flowing
boed, $18.15 per boe of proved reserves and $13.02 per boe of P+P reserves. This
transaction closed March 1, 2010, with an October 1, 2009 effective
date.  Net proceeds from this disposition in the amount of $177
million were used to reduce outstanding debt under Provident's Canadian Credit
Facility.







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Effective
January 1, 2010, the Trust completed an additional internal reorganization
intended to further segregate and consolidate the Trust's subsidiaries along
business lines.  As a result of the internal reorganization
transactions, the Trust's oil and natural gas production business was
consolidated in PERI and certain of its subsidiaries.




RISK
MANAGEMENT




Details
of Provident's commodity price risk management program and the financial
instruments in place at December 31, 2009 are available in Note 14 to the
Trust's audited consolidated financial statements and management's discussion
and analysis for the year ended December 31, 2009 and are incorporated by
reference herein.  The Trust's audited consolidated financial
statements and management's discussion and analysis for the year ended December
31, 2009 have been filed on SEDAR and are available under the Trust's issuer
profile at www.sedar.com.




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




OIL
AND NATURAL GAS OPERATIONS




Information
concerning Provident's oil and gas reserves and other information relating
thereto is contained in the Statement of Reserves Data and other Oil and Gas
Information on Form 51-101F1 which has been filed on SEDAR at
www.sedar.com.




Provident's
reserves were evaluated by McDaniel and AJM effective December 31, 2009, in
accordance with NI 51-101.  McDaniel and AJM are independent qualified
reserves evaluators appointed pursuant to NI 51-101.  The McDaniel
evaluation report is dated March 1, 2010 with a preparation date of December 31,
2009.  The AJM evaluation report is dated March 1, 2010 with a
preparation date of December 31, 2009.




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 and AJM both dated
March 1, 2010 and the Report of Management and Directors on Oil and Gas
Disclosure on Form 51-101F3 dated March 11, 2010 have been filed on SEDAR at
www.sedar.com and are incorporated by reference in this Annual Information
Form.




NATURAL
GAS LIQUIDS MIDSTREAM PROCESSING AND MARKETING OPERATIONS




The
Midstream Business




The
Midstream Business unit extracts, processes, stores, transports and markets NGLs
for Provident and offers these services to third party customers.  The
Midstream Business contains three business lines.




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


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




·
            100
      percent ownership of a 50,000 bpd debutanizer at Empress Alberta which
      removes condensate from the NGL mix for sale as a diluent to blend with
      heavy oil.




·
            50
      percent ownership in the 130,000 bpd Kerrobert Pipeline which transports
      NGL from Empress to Kerrobert, Saskatchewan, and 50 percent ownership in a
      2.5 mmbbls underground storage facility near Kerrobert which facilitates
      injection of NGLs into the Enbridge Pipeline System.  Along the
      Enbridge Pipeline System, Provident holds 18.3 percent ownership of a
      300,000 barrel storage staging facility required for transfer of NGL
      between Enbridge lines at Superior, Wisconsin, and 18.3 percent ownership
      of the 10,000 bpd Superior Depropanizer which extracts up to 6,600 bpd of
      propane for sale in the local
market.





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-





·
            In
      Sarnia, Ontario, 16.5 percent ownership of an approximately 150,000 bpd
      fractionator, 1.7 mmbbls of raw product storage capacity and 18.0 percent
      of 5.0 mmbbls of finished product storage and a rail, truck and pipeline
      terminalling facility.  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 300 rail cars in the east under long term
      lease agreement.




The
Empress East business line extracts NGLs from natural gas at the Empress
straddle plants and sells finished products into markets in Central Canada and
the Eastern United States.  The margin in this business is determined
primarily by the “frac spread”, which represents the difference between the
selling prices for propane-plus and the input cost of the natural gas required
to produce the respective NGL products.  The frac spread can change
significantly from period to period depending on the relationship between crude
oil and natural gas prices (the "frac spread ratio"), absolute commodity prices,
and changes in the Canadian to US dollar foreign exchange
rate.  Traditionally a higher frac spread ratio and higher crude oil
prices will result in stronger business line margins.  There is also a
differential between propane, butane and condensate (collectively, these
products are referred to as "propane-plus") prices and crude oil prices which
can change prices received and margins realized for Midstream products separate
from frac spread ratio and crude oil price changes.  Operating margins
reflect the prices realized on sale of these products less the weighted average
cost of purchasing, fractionating, storing and transporting the
products.  The propane business is seasonal and carries inventory that
generally builds over the second and third quarters of the year and is sold in
the fourth quarter and the first quarter of the following year.




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, finished product truck loading facilities, seven million gross
      barrels of salt cavern storage, and a 75,000 bpd condensate rail
      offloading facility with a 500 railcar marshalling and storage
      yard.




·
            The
      Redwater facility is the only facility in Western Canada that can
      fractionate a high sulphur ethane-plus
mix.




·
            Approximately
      7,000 bpd of leased fractionation 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 kilometre 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.  The LGS connects to Pembina
      Pipeline at La Glace Alberta. Provident has long-term shipping rights on
      Pembina Pipeline, extending the NGL supply transportation network through
      to the Redwater fractionation
facility.
  ·
              A
      rail car fleet of approximately 700 rail cars in the west under long term
      lease agreement.





- 25
-





The
Redwater West business line purchases an NGL mix from various producers and
fractionates it into finished products at the Redwater fractionation facility
near Edmonton, Alberta.  Because the feedstock for this business line
is primarily NGL mix rather than natural gas, the frac spread has a smaller
impact on margin than in the Empress East business line.  This
facility also has the largest rail rack in western Canada to receive products
for delivery into the local condensate market.  Provident has
considerably increased its condensate market presence at Redwater through
condensate marketing, third-party terminalling and, most recently, condensate
storage.  During the third quarter of 2009, two of Provident's three
new 500,000 barrel storage caverns at Redwater were placed into condensate
service.  Income generated from the condensate terminal and caverns
which relates to third-party terminalling and storage is included within the
Commercial Services business line, while income relating to proprietary
condensate marketing activities remains within the Redwater West business
line.




The
Empress East and Redwater West business lines are supported by Provident's
integrated marketing arm which has offices in Calgary, Alberta, Sarnia, Ontario,
and Houston, Texas and operates under the brand name Kinetic.  Rather
than selling NGL produced by the Empress East and Redwater West facilities at
the plant gate, the marketing and logistics group utilizes Provident's
integrated suite of transportation, storage and logistics assets to access
markets across North America.  Due to its broad marketing scope,
Provident's NGL products are priced based on multiple pricing
indices.  These indices generally correspond with the four major NGL
trading hubs in North America which are located in Mont Belvieu, Texas, Conway,
Kansas, Edmonton, Alberta, and Sarnia, Ontario.  Mont Belvieu, the
largest NGL trading center, serves as the reference point for NGL pricing in
North America.  By strategically building inventories of specification
products which are then distributed into premium-priced markets across North
America during periods of high seasonal demand, Provident is able to optimize
the margins it earns from its extraction and fractionation operations.
Provident's marketing group also generates margins by taking advantage of
locational price differentials and arbitrage trading
opportunities.  Margins generated through marketing activities are
included within the Empress East and Redwater West business lines.




The
Commercial Services business line includes services such as fractionation,
storage and loading and unloading 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.  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 price volatility and are thus relatively stable.




Long
term contracts




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




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




In 2006
and early 2007, Provident commissioned a condensate rail off-loading terminal at
Redwater with current capacity of 75,000 bpd, a significant portion of which is
under long term contracts with various third parties, a number of which are
major energy producers.




The
majority of the condensate storage capacity at Redwater is sold under long term
contracts to various third parties, a number of which are major energy
producers, with terms averaging from two to five years.





- 26
-





Provident
has a long term contract on a cost of service basis for the majority of its
50,000 bpd Empress debutanizer facility with a major energy
producer.




MARKET
FOR SECURITIES




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




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




Toronto
Stock Exchange




Trust
Units (PVE.UN)




Period
            High
      ($)
            Low
      ($)
            Volume
      (000's)2009January
            6.61
            5.33
            6,068February
            5.66
            3.59
            6,591March
            5.17
            2.90
            9,219April
            5.61
            4.50
            5,894May
            6.50
            5.23
            9,736June
            6.43
            5.38
            7,180July
            5.65
            4.69
            6,309August
            5.85
            5.40
            5,421September
            6.46
            5.54
            5,880October
            7.22
            5.64
            7,290November
            7.36
            6.46
            6,144December
            7.35
            6.71
            4,912




8
Percent Debentures (PVE.DB.B)




Period
            High
      ($)
            Low
      ($)
            Volume2009January
            100.00
            96.02
            12,930February
            100.00
            97.25
            5,720March
            100.00
            97.00
            39,850April
            100.98
            99.35
            5,740May
            100.45
            99.98
            16,840June
            100.99
            100.25
            40,350July
            100.25
            99.50
            2,040




Note:


(1)
            The
      Trust repaid $25.1 million to the holders of the 8 Percent Debentures,
      which matured on July 31, 2009.  The 8 Percent Debentures were
      subsequently de-listed from the TSX.  No 8 Percent Debentures
      remain outstanding as of the date
hereof.








- 27
-




Initial
6.5 Percent Debentures (PVE.DB.C)




Period
            High
      ($)
            Low
      ($)
            Volume2009January
            78.00
            65.00
            9,360February
            78.97
            70.75
            5,130March
            74.00
            60.00
            10,990April
            78.00
            72.60
            36,680May
            89.50
            77.50
            75,500June
            92.50
            87.01
            74,250July
            94.74
            92.00
            13,960August
            99.49
            94.26
            19,395September
            99.00
            97.80
            18,680October
            99.79
            97.81
            77,450November
            102.00
            98.31
            23,510December
            103.00
            100.01
            7,890




Supplemental 6.5 Percent
Debentures (PVE.DB.D)




Period
            High
      ($)
            Low
      ($)
            Volume2009January
            88.00
            77.95
            8,930February
            82.99
            78.00
            5,640March
            80.00
            70.00
            140,780April
            85.00
            79.00
            55,140May
            93.00
            84.95
            32,430June
            96.00
            93.25
            17,320July
            97.00
            94.50
            60,030August
            99.50
            96.50
            47,030September
            99.99
            98.25
            36,240October
            100.00
            98.56
            27,420November
            101.75
            99.50
            25,950December
            101.99
            100.50
            14,930




New
York Stock Exchange




Trust
Units (PVX)




Period
            High
      (U.S.$)
            Low
      (U.S.$)
            Volume
      (000's)2009January
            5.60
            4.31
            26,393February
            4.60
            2.88
            26,909March
            4.20
            2.23
            39,274April
            4.60
            3.55
            22,340May
            5.56
            4.40
            31,638June
            5.70
            4.67
            29,547July
            5.12
            4.00
            24,682August
            5.37
            4.95
            20,977September
            6.08
            5.00
            26,381October
            6.87
            5.19
            41,871November
            6.99
            6.01
            35,888December
            6.90
            6.35
            26,232




RECORD
OF CASH DISTRIBUTIONS




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




Distribution
      Amount
                (Cdn$)
            
            Distribution
      Amount
                (US$)(1)2001
              March
      - December
            $2.54
            
            $1.642002
              January
      - December
            $2.03
            
            $1.292003
              January
      - December
            $2.06
            
            $1.47  - 28
-
 2004January
      - December
            $1.44
            
            $1.102005January
      - December
            $1.44
            
            $1.202006January
      - December
            $1.44
            
            $1.262007January
      - December
            $1.44
            
            $1.352008January
      - December
            $1.38
            
            $1.292009January
      - December
            $0.75
            
            $0.672010January
            $0.06
            
            $0.06February
            $0.06
            
            $0.06March
            $0.06
            
            $0.06Total
      to date for 2009
            $0.18
            
            $0.18





Since its
inception, the Trust has paid an aggregate of $14.70 (U.S.$11.45) 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 2008.


- 29
-








Premium
                Distribution
              5
      percent Discounted Unit Price for
                Distribution
      Reinvestment Purchase PlansPayable
      Date
              Regular
                Distribution
              102
      percent of Regular
                Distribution(1)
              15
      Day Weighted
                Average
      Unit
                Price(2)
              5
      percent Discounted
                Unit
      Price15-March-10
              $0.06
              $0.0612
              $8.4212
              $8.000112-Feb-10
              $0.06
              $0.0612
              $8.3999
              $7.949915-Jan-10
              $0.06
              $0.0612
              $7.5170
              $7.141215-Dec-09
              $0.06
              $0.0612
              $6.8251
              $6.483813-Nov-09
              $0.06
              $0.0612
              $6.9186
              $6.572715-Oct-09
              $0.06
              $0.0612
              $6.0783
              $5.774415-Sept-09
              $0.06
              $0.0612
              $5.6916
              $5.407014-Aug-09
              $0.06
              $0.0612
              $5.4225
              $5.151415-July-09
              $0.06
              $0.0612
              $5.3299
              $5.063415-Jun-09
              $0.06
              $0.0612
              $5.8104
              $5.519915-May-09
              $0.06
              $0.0612
              $5.6934
              $5.408715-Apr-09
              $0.06
              $0.0612
              $4.9339
              $4.687213-Mar-09
              $0.06
              $0.0612
              $3.3584
              $3.190513-Feb-09
              $0.09
              $0.0918
              $5.5381
              $5.621215-Jan-09
              $0.09
              $0.0918
              $5.6991
              $5.414115-Dec-08
              $0.09
              $0.0918
              $5.4147
              $5.144014-Nov-08
              $0.12
              $0.1224
              $7.2646
              $6.901415-Oct-08
              $0.12
              $0.1224
              $8.3030
              $7.887915-Sept-08
              $0.12
              $0.1224
              $10.6818
              $10.147715-Aug-08
              $0.12
              $0.1224
              $10.5688
              $10.040415-July-08
              $0.12
              $0.1224
              $11.0744
              $10.520713-Jun-08
              $0.12
              $0.1224
              $11.5608
              $10.982615-May-08
              $0.12
              $0.1224
              $11.2476
              $10.685215-Apr-08
              $0.12
              $0.1224
              $11.0007
              $10.450714-March-08
              $0.12
              $0.1224
              $10.6251
              $10.093815-Feb-08
              $0.12
              $0.1224
              $10.1047
              $9.599515-Jan-08
              $0.12
              $0.1224
              $10.0892
              $9.5847





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 under the Trust's issuer profile on SEDAR at
www.sedar.com and on the Trust's website at www.providentenergy.com or by
contacting Provident by phone at (403) 296-2233 or by mail at 2100, 250 -
2nd
Street S.W., Calgary, Alberta T2P 0C1.




DIRECTORS
AND OFFICERS




The
following are the names and municipality of residence of the directors and
officers of PEL, their principal position with PEL 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 13, 2010.




- 30
-


Name
      and Background
            Number
      of Trust Units
                Beneficially
      Owned
                or
      Controlled or DirectedJohn B. Zaozirny(2)
      of Calgary, Alberta is Chairman of the Board.  He also serves as
      vice-chairman and director of Canaccord Financial Inc.  Mr.
      Zaozirny was the Alberta Minister of Energy and Natural Resources from
      1982 to 1986.  He has been a director of PEL since 2001 and is
      also a director of Bankers Petroleum Ltd., Canadian Oil Sands Trust,
      Coastal Energy Company, Computer Modelling Group Ltd., Pacific Rubiales
      Energy Corp. and PetroAmerica Oil Corporation and is chair and director of
      Pengrowth Energy Trust and Lead Independent Director of Terravest Income
      Fund.
            93,669Grant D. Billing(2)
      of Calgary, Alberta is the Chairman and Chief Executive Officer and a
      director of Superior Plus Corp., a diversified company, since
      1998.  He has been a director of PEL since 2001.
            69,700(4)Thomas W. Buchanan of
      Calgary, Alberta has been the Chief Executive Officer and a director of
      PEL since March 2001.  Mr. Buchanan has also been the President
      of PEL 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 Emera Inc. and Hawk Exploration Ltd.
            980,227(4)Hugh A. Fergusson(1)(3)
      of Calgary, Alberta is the former Vice President and Director with Dow
      Chemical Canada Inc.  He has been a director of PEL since 2005
      and is also a director of Altagas Income Trust and Canexus Income
      Fund.
            12,450(4)Randall J. Findlay(3)of Calgary, Alberta has been a director of PEL since March
      2001.  Mr. Findlay was also the President of PEL from March 2001
      until June 30, 2006.  Prior thereto he was Executive Vice
      President and Chief Operating Officer of Founders Energy Ltd. from
      December 1999 to March 2001.  He is also chair and a director of
      Canadian Helicopters Income Fund and a director of Pembina Pipelines
      Income Fund, Superior Plus Corp. and Wellpoint Systems Inc.
            457,378Norman R. Gish(2)(5)
      of Calgary, Alberta is an independent businessman.  He is also a
      director of Superior Plus Corp. and Chairman and Director of Quadrise
      Canada Corporation. Previously, president of Gish Consulting Inc. (energy
      consulting) from 2001 to 2007.
            7,000(4)Bruce R. Libin(1)(3)
      of Calgary, Alberta is President and a Director of Destiny Resource
      Services Corp., a resource services company.  From December 2000
      to March 2010 he was Executive Chairman and Chief Executive Officer of
      Destiny Resource Services Corp.  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 PEL since 2001 and is also Chairman of Winstar Resources
      Ltd.
            190,602Dr. Robert W.
      Mitchell(3)
      of Calgary, Alberta has been an independent businessman since September
      2003.  From 1984 to September 2003, he was Executive Vice
      President of Talisman Energy Inc., a public oil and gas
      company.  He has been a director of PEL since 2004 and is also a
      director of Winstar Resources Ltd.
            15,000M.H. (Mike) Shaikh(1)(6)
      of Calgary, Alberta is a chartered accountant.  He has been a
      director of PEL since 2001 and is also a director of Hawk Exploration
      Ltd.
            173,942(4)Jeffrey T. Smith(2)(3)
      of Calgary, Alberta is an independent businessman.  He has been
      a director of PEL since 2001 and is also a director of Compton Petroleum
      Ltd.
            10,400


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. Shaikh also
      holds $250,000 principal amount of the Supplemental6.50 Percent
      Debentures. Mr. Gish also holds $110,000 principal amount of the
      Supplemental 6.50 Percent
Debentures.







- 31
-





(5)
            Mr.
      Gish was until August 20, 2009 a director of 4504020 Canada Inc. (formerly
      Railpower Technologies Corp. ("Railpower"), a reporting issuer in all
      provinces and territories of Canada that filed for court protection under
      the Companies' Creditors Arrangement Act (Canada) in Canada and under
      Chapter 15 of the U.S. Bankruptcy Code with the United States Bankruptcy
      Court for the Western District of Pennsylvania on February 4, 2009 and
      February 6, 2009, respectively.  On May 29, 2009, Railpower
      concluded the sale of all of its assets, except cash on hand and on
      deposit in financial institution, the land and property located in
      St.-Jean-sur-Richelieu (Quebec) and two road switching locomotives, to
      R.J. Corman Railroad Group LLC, a Kentucky limited liability
      company.  The court protection was effective until March 8, 2010
      to allow time for Railpower to complete and file a joint plan of
      arrangement for consideration by its creditors and the
    court.




(6)
            Mr.
      Shaikh was a director of Mystique Energy Inc. ("Mystique") from November
      11, 2004 until his resignation on April 24, 2007. On April 25, 2007 the
      Court of Queen's Bench of Alberta (the "Court") granted an initial order
      to Mystique for creditor protection under the Companies' Creditors
      Arrangement Act ("CCAA"). The initial order grants CCAA protection for an
      initial period of 30 days, expiring May 24, 2007, to be extended
      thereafter as the Court deems appropriate. The CCAA proceedings have been
      completed and Mystique has settled with its
  creditors.




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.




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 at which time he joined
Provident.  He is also a former director of the Petroleum Technology
Research Centre and a past chair of the Canadian Oil Sands Network for Research
and Development.  He also currently serves as a Governor 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.







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Lynn
M. Rannelli




Assistant
Corporate Secretary




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




Cameron
G. Vouri




President,
Upstream 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 at which time he joined
Founders.




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.  After several years of general accounting experience,
Mr. Walker began working in the oil and gas industry 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, 2009, the Board of Directors had three standing
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.







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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 Provident'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. Norman
Gish, (Chairman), Mr. Grant D. Billing, Mr. Jeffrey T. Smith 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. 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.







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Disclosure
Committee




The
Disclosure Committee is comprised of the President and Chief Executive Officer,
the Executive Vice President, Operations and Chief Operating Officer, the Senior
Vice President, Finance and Chief Financial Officer, the Vice President,
Corporate Services, the Director, Investor Relations and Communications, the
Director, Financial Reporting and Performance Measurement and the Assistant
Corporate Secretary of PEL.  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 PEL are engaged in and will continue to engage in
other activities in the energy industry and, as a result of these and other
activities, the directors and officers of PEL 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, PEL is not aware of any existing or potential material conflicts of
interest between PEL and a director or officer of PEL.




AUDIT
COMMITTEE INFORMATION




Composition
of the Audit Committee




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




Audit
Committee Charter




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




Relevant
Education and Experience of Each Audit Committee Member




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






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-




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












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External
Auditor Service Fees




The
following table sets forth information about the fees billed to the Trust and
its Canadian and U.S. subsidiaries for professional services provided by
PricewaterhouseCoopers llp during fiscal 2009
and 2008.  PricewaterhouseCoopers llp is independent in
accordance with the auditor's rules of professional conduct in
Canada.




(CDN$)
            2009
            2008Audit
      Fees
            $856,000
            $1,119,000Audit-Related
      Fees
            197,000
            131,000Tax
      Fees
            24,622
            197,920All
      Other Fees
            12,727
            315,063Total
            $1,090,349
            $1,762,983





Audit
Fees




Fees for
audit services totalled approximately $0.9 millionin 2009 and
approximately $1.1 millionin 2008, including fees
associated with the annual audit, the reviews of the Trust's quarterly reports,
statutory audits and regulatory filings.




Audit-Related
Fees




Fees for
audit-related services totalled approximately $0.2 million in 2009 and
approximately $0.1 million in 2008.  Audit related services include
advisory services in connection with the transition to International Financial
Reporting Standards and French translation services.




Tax
Fees




Fees for
tax services totalled $24,622 in 2009 and approximately $0.2 million in
2008.  Fees for tax services include assistance with tax return
preparation, tax planning and tax advice services.




All
Other Fees




Fees for
all other services totalled $12,727 in 2009 and approximately $0.3 million in
2008 for miscellaneous consulting services primarily related to
valuations.




In
accordance with Provident's procedures for the approval of audit and non-audit
services by PricewaterhouseCoopers llp (the
"Procedures"),
the Audit Committee has pre-approved the services of external auditors listed in
the Procedures.  This general pre-approval of services set forth in
the Procedures is brought to the Audit Committee for review and renewal on an
annual basis.  Management has agreed to seek the guidance of the
Chairman of the Audit Committee if there is any ambiguity about whether a
particular service is pre-approved.




In the
case of proposed engagements of PricewaterhouseCoopers llpinvolving services
set forth in the Procedures in which the fees for such services are expected to
exceed $100,000, specific pre-approval must be obtained from the Audit
Committee.  In these circumstances in which specific pre-approval is
required, the Audit Committee has delegated the authority to effect such
pre-approval to the Chairman of the Audit Committee.







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-





In
respect of services set forth in the Procedures in which the fees for a
particular engagement are expected to be less than or equal to $100,000, the
Chairman of the Audit Committee must be notified expeditiously of any such
services commenced by the auditors.




If an
engagement with PricewaterhouseCoopers llp for a particular
service is contemplated, and is neither prohibited under the terms of the
Procedures nor covered under the range of services set forth in the Procedures,
the engagement is subject to the pre-approval of the Chairman of the Audit
Committee.




All
pre-approvals granted by the Chairman of the Audit Committee must be presented
to the full Audit Committee at its next meeting.




Prohibited
services may not be pre-approved by the Audit Committee or pursuant to the
delegated authority granted to the Chairman of the Audit
Committee.  The Trust has complied with applicable rules regulating
the provision of non-audit services to the Trust by its external
auditor.




INFORMATION
CONCERNING THE OIL AND GAS INDUSTRY




Canadian
Government Regulation




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




Pricing
and Marketing - Oil




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




Pricing
and Marketing - Natural Gas




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




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







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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 carried forward most of the material energy terms
contained in the Canada-U.S. Free Trade Agreement.  In the context of
energy resources, Canada is 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
that govern land tenure, royalties, production rates, environmental protection
and other matters.  The royalty regime is a significant factor in the
profitability of oil and natural gas production.  Royalties payable on
production from lands other than Crown lands are determined by negotiations
between the mineral owner and the lessee.  Crown royalties are
determined by governmental regulation and are generally calculated as a
percentage of the value of the gross production, and the rate of royalties
payable generally depends in part on well productivity, geographical location,
field discovery data and the type or quality of the petroleum product
produced.




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




The
Government of Alberta receives royalties on the production of natural resources
from lands in which it owns the mineral rights.  Royalties payable
pursuant to petroleum and natural gas leases with the Government of Alberta are
ad valorem royalties,
assessed on a sliding scale where the rate changes depending on oil or natural
gas prices and the level of production.  On October 25, 2007, the
Government of Alberta unveiled a new royalty regime which introduced new
royalties for conventional oil, natural gas and bitumen and which became
effective January 1, 2009 (the "2009 royalty regime").




Under the
2009 royalty regime, royalties payable to the Crown in right of the Province of
Alberta (the "Crown") for conventional oil are determined based upon a sliding
rate formula containing elements that account for oil price and well
production.  Royalty rates for conventional oil range up to 50
percent, with rate caps once the price of conventional oil reaches Cdn.$120 per
barrel.  In March, 2010, the Government of Alberta announced that,
effective January 1, 2011, the maximum royalty rate for conventional oil would
be reduced to 40 percent.




Under the
2009 royalty regime, natural gas royalties are determined based upon a sliding
rate formula sensitive to price and well production, though a form of deep gas
royalty holiday has been retained and lower royalty rates apply for wells with
less productivity.  Royalty rates for natural gas range from five
percent to 50 percent with rate caps once the price of natural gas reaches
$16.00/gj.  Royalties for natural gas liquids are set at 40 percent
for pentanes and 30 percent for butanes and propane.  In March, 2010,
the Government of Alberta announced that, effective January 1, 2011, the maximum
royalty rate for natural gas would be reduced to 36 percent and that further
analysis of natural gas royalty components was underway and would be concluded
and the results announced in May 2010.





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In
connection with the 2009 royalty regime, the Alberta Department of Energy also
announced its intent to implement a shallow rights reversion
program.  If this program receives legislative approval, it is
proposed that, beginning in 2011, geological zones above the shallowest
productive zone of lands subject to a Crown lease would revert to the Crown in
Alberta at the expiry of the primary term of the lease or, in the case of Crown
leases already past their primary term, after notice thereof to the
lessee.




In
November, 2008, the Government of Alberta announced an optional five year
transitional royalty program which would provide companies drilling new
conventional oil and gas wells, which wells are commenced between November 19,
2008 and December 31, 2013 and drilled to depths of between 1,000 to 3,500
metres, with a one-time option to elect transitional royalty rates over the
rates applicable pursuant to the 2009 royalty regime.  All wells
drilled for which transitional rates are elected will revert to the new royalty
regime effective January 1, 2014.  In March, 2010, the Government of
Alberta announced that while the transitional royalty will continue until
December 31, 2013 as originally announced, effective January 1, 2011, companies
will not be allowed to select the transitional royalty rates for new wells and
those that have selected transitional royalty rates for new wells prior to
January 1, 2011 would be allowed to switch to the new rates effective as of
January 1, 2011.




In 2009,
the Government of Alberta announced an energy incentive program to encourage
activity in the conventional oil and gas sector in Alberta.  The
program includes provisions for a drilling royalty credit of $200 per meter
drilled on new conventional oil and natural gas wells on Crown lands that are
spud and on which drilling is finished between April 1, 2009 and before April 1,
2011.  The incentive program also provides for a maximum royalty rate
of five (5) percent applicable for 12 calendar months or 50,000 barrels or 500
mmcf of production, whichever is reached first, applicable to new wells on Crown
lands that begin producing conventional oil and natural gas between April 1,
2009 and March 31, 2011.




Environmental
Regulation




The oil
and natural gas industry is currently subject to environmental regulation
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, pipeline and
facility sites be abandoned and reclaimed to the satisfaction of provincial
authorities.  A breach of such legislation may result in the
imposition of fines and penalties, the suspension or revocation of necessary
licenses and civil liability.




In
December, 2002, the Government of Canada ratified the Kyoto Protocol (the
"Protocol"). The Protocol calls for Canada to reduce its emissions of greenhouse
gas, or GHGs, to 6% below 1990 "business as usual" levels between 2008 and
2012.  It remains uncertain whether the Kyoto target of 6% below 1990
GHG emission levels will be enforced in Canada.  On April 26, 2007 the
Canadian Federal Government released a "Regulatory Framework for Air Emissions",
or the Framework, which outlines proposed new requirements governing the
emission of GHGs and other industrial air pollutants, including sulphur oxides,
volatile organic compounds, particulate matter, and possibly additional
sector-specific pollutants, in accordance with the Canadian Federal Government’s
Notice of Intent to Develop and Implement Regulations and Other Measures to
Reduce Air Emissions released on October 19, 2006. The Government of Canada and
the Province of Alberta released on January 31, 2008 the final report of the
Canada-Alberta ecoENERGY Carbon Capture and Storage Task Force, which recommends
among others: (i) incorporating carbon capture and storage into Canada's clean
air regulations; (ii) allocating new funding into projects through competitive
process; and (iii) targeting research to lower the cost of
technology.







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On March
10, 2008, the Government of Canada released "Turning the Corner – Taking Action
to Fight Climate Change", or Turning the Corner, which provides some additional
guidance with respect to the Government of Canada's plan to reduce GHG emissions
by 20% by 2020 and by 60% to 70% by 2050. Turning the Corner is primarily
directed towards industrial emissions from certain specified industries
including the oil sands, oil and gas and refining industries. Turning the Corner
is intended to force industry to reduce GHG emissions and to create a carbon
emissions trading market, including an offset system, to provide incentives to
reduce GHG emission and establish a market price for carbon. Turning the Corner
provides for: (i) mandatory reductions of 18% from the 2006 baseline starting in
2010 and by an additional 2% in subsequent years for existing facilities; (ii)
new facilities built between 2004 and 2011 will have mandatory emissions
standards based upon clean fuel standards (natural gas) with a 2% reduction
below the third year's intensity levels; and (iii) oil sands plants built in
2012 and later which use heavier hydrocarbons and upgraders and in situ
production will have mandatory standards in 2018 based upon carbon capture and
storage standards or other green technologies intensity. For the upstream oil
and gas industry, Turning the Corner also provides for a company threshold of
10,000 boe per day and facility threshold of 3,000 tonnes of CO2.  Draft
regulations were expected to be available for public comment in the Fall of 2008
but have not yet been released, and it is not known if or when such regulations
will be released or implemented.




The
proposed compliance mechanisms include an emissions credit trading system for
GHGs and certain industrial air pollutants, and several options for companies to
choose among to meet GHG emission intensity reduction targets and encourage the
development of new emission reduction technologies, including the option of
making payments into a technology fund, an emissions and offset trading system,
limited credits for emission reductions created between 1992 and 2006, and
international emission credits under the clean development mechanism under the
Kyoto Protocol for up to 10% of each firm's regulatory obligation.




Recently,
on January 30, 2010, the Government of Canada submitted to the United Nations
Framework on Climate Change a non-legally binding commitment under the
Copenhagen Accord to reduce Canada's emissions of GHGs by 17% from 2005 emission
levels.  This is a significant change from previous international
commitments of a 20% reduction in emissions from 2006 levels by
2020.  The Government of Canada signalled that the new national
emission reduction target was to be aligned with emission reduction targets of
the United States.  It is unclear how the new proposed national
emission reduction target is to be met and whether the previous announced
proposed regulatory Framework will proceed or be replaced with a new regulatory
framework.  It is reasonably likely that new federal legislation
requiring emissions reductions similar to the Framework will be enacted in
Canada around the same time as similar legislation is enacted in the United
States.  Such federal legislation could have a material effect on the
development of Provident's assets.




Environmental
legislation in the Province of Alberta has largely been consolidated into the
Environmental Protection and
Enhancement Act(Alberta), theWater Act(Alberta), and the
Oil and Gas Conservation
Act (Alberta) (the "OGCA"). These statutes impose environmental
standards, require compliance, reporting and monitoring obligations, and impose
penalties. In addition, the emission reduction requirements in the Climate Change and Emissions
Management Act(Alberta) came into effect on July 1, 2007. Under this
legislation, Alberta facilities emitting more than 100,000 tonnes of GHGs a year
must reduce their emissions intensity by 12%.  Companies have four
options to choose from in order to meet the reduction requirements outlined in
this legislation, and these are: (i) by making improvement to operations that
result in reductions; (ii) by purchasing emission credits from other sectors or
facilities that have reduced their emissions below the required emission
intensity reduction levels; (iii) by purchasing off-set credits from other
sectors or facilities that have emissions below the 100,000 tonne threshold and
are voluntarily reducing their emissions in Alberta; or (iv) by contributing to
the Climate Change and Emissions Management Fund.  Companies can
choose one of these options or a combination thereof.  Provident is
committed to meeting its responsibilities to protect the environment wherever it
operates and anticipates making increased expenditures of both a capital and an
expense nature as a result of the increasingly stringent laws relating to the
protection of the environment, and will be taking such steps as required to
ensure compliance with the environmental protection legislation in all
jurisdictions in which it operates. The Trust believes that it is reasonably
likely that the trend towards stricter standards in environmental legislation
and regulation will continue.







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Provident
has made 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.  Additional information relating to the Trust's asset
retirement obligation is contained in Note 10 to the Trust's audited
consolidated financial statements for the year ended December 31, 2009
incorporated by reference herein.




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.




INFORMATION
CONCERNING THE NATURAL GAS LIQUIDS MIDSTREAM PROCESSING AND MARKETING
INDUSTRY




General




The NGL
industry involves the production, transportation and marketing of products that
are extracted from natural gas prior to its sale to end use
customers.  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.




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




NGL
Extraction




A primary
component of the NGL value chain is 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.  Pipeline quality gas may then be transported and sold
to end users or processed at straddle plants to recover additional NGLs,
including ethane.  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.




NGL
Fractionation
  NGL mix
extracted at field plants is transported to fractionation facilities, which
enhances its value by separating the mix into its components: ethane, propane,
butane and pentanes-plus. Fractionation generally does not occur at field
plants, but rather at a central location.  The NGL mixes are moved by
truck or pipeline to fractionation facilities.  Once fractionated, the
products are then transported to markets in Alberta or outside the province, by
pipeline, truck or rail.


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NGL
Transportation




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




NGL
Storage




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




NGL
Marketing




The
markets for NGLs are North American in scope with end uses varying substantially
by product.  NGLs are used directly as heating and transportation
fuels and also as a feedstock for the petrochemical and crude oil refining
industries.




Ethane is
used primarily as feedstock for the petrochemical industry.




Propane
is the most versatile of the NGL products from a marketing perspective. Uses for
propane include home and commercial heating, crop drying, cooking and motor
fuel.




Butane is
used primarily in gasoline blending, either directly or in the production of
iso-octane and as a diluent for heavy oil.




Pentanes-plus
is used primarily as a diluent to blend with heavy crudes to decrease the
viscosity and density of these crudes, allowing them to be transported in
pipelines. In addition, pentanes-plus are used as a refinery feedstock in the
production of gasolines.




Commercial
Arrangements




An
extraction facility's fees may be based on a cost-of-service arrangement
(reimbursement for operating expenses plus a return on capital employed), a
fixed charge per unit of throughput, or some combination of these fee
structures.  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.  For the right to extract NGLs from the gas
stream, extraction facility owners generally pay the owners of the gas a premium
over the shrinkage gas price, which effectively amounts to sharing with owners
of the gas a portion of the value that is added through the recovery
and sale of NGLs.  Other costs of extraction 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, a flow through of a portion of plant operating costs
and an additional fixed fee to cover capital employed.  As a result,
the ethane operations of an extraction facility generally generate a relatively
predictable cash flow stream.





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The
extraction facility's other revenues are often tied to the market prices of
propane, butane and pentanes-plus which in turn are typically correlated as a
percentage of the price of crude oil.




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
fees charged vary depending upon the package of services provided. Facility
expenses include operating costs associated with gathering, transporting,
fractionating, storing and distributing the NGL mix. Hence, profit is determined
by the difference between the fees charged and the costs incurred for the
service provided rather than on the spread between natural gas and NGL prices as
in the case of an extraction plant.  The owner of a fractionator may
also purchase NGL streams in the field for its own account, transport and
process the stream, then sell the resulting products in the
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).




RISK
FACTORS




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




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




Oil
and Gas Production Risk Factors




Exploration
and Development




Exploration
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





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in
personal injuries, loss of life and damage to property of Provident and
others.  Provident will have both safety and environmental policies in
place to protect its operators and employees, as well as to meet the regulatory
requirements in those areas where it operates.  In addition, Provident
will have liability insurance policies in place, in such amounts as it considers
adequate, however, it will not be fully insured against all of these risks, nor
are all such risks insurable.




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




Oil
and Natural Gas Prices




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




Marketing




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




Capital
Investment




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




Reserves




Although
McDaniel, AJM 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 undeveloped
reserves estimated may require revision based on the actual development
strategies employed to prove such reserves and results
achieved.  Declines in the reserves of Provident, which are not offset
by the acquisition, or development of additional reserves may reduce the
underlying value of Trust Units to Unitholders.  The value of the
Trust Units attributable to the oil and gas reserves will have no value
once all of the oil and natural gas reserves of Provident have been
produced.  As a result, holders of Trust Units will have to obtain the
return of capital invested out of cash flow derived from their investment in
such Trust Units.


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.


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Environmental
Concerns




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




Delay
in Cash Distributions




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




Reliance
on Provident




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




Depletion
of Reserves




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




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




To the
extent that external sources of capital, including the issuance of additional
Trust Units (through public offerings, the DRIP or otherwise) become limited or
unavailable, Provident's ability to make the necessary capital investments to
maintain or expand its oil and natural gas reserves will be
impaired.  To the
extent that Provident is required to use cash flow to finance capital
expenditures or property acquisitions, the level of Distributable Cash will
be reduced. 
 There can
be no assurance that Provident will be successful in developing or acquiring
additional reserves on terms that meet the Trust's investment
objectives.





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Write-downs
of Oil and Gas Property Investments




Lower oil
and gas prices increase the risk of write-downs of Provident’s oil and gas
property investments.  Under applicable accounting rules, the net
capitalized cost of oil and gas properties may not exceed a "ceiling limit" that
is based, in part, upon estimated future net cash flows from
reserves.  If oil and natural gas prices decline, Provident’s net
capitalized cost may exceed this cost ceiling, ultimately resulting in a charge
against Provident’s earnings.  While these write-downs would not
affect cash flow, the charge against earnings could be viewed unfavourably in
the market.




Regulatory
Matters




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




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




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




Kyoto
Protocol




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







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not be
recognized or qualify under future legislative or regulatory regimes as
mitigation for the emission of greenhouse gases by Provident. See "Information
Concerning Oil and Gas Industry - Environmental Regulation".




Royalties




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




In
Alberta, the Crown royalty rates on conventional oil and natural gas fluctuate,
depending on when a well was drilled, well depth, well production volume and the
price of oil and natural gas. On October 25, 2007, the Alberta provincial
government introduced a new royalty regime which became effective on January 1,
2009 and is applicable to all existing conventional oil and natural gas wells in
Alberta. The new royalty regime assesses the applicable royalty rate on a well
by well basis using a sliding scale which takes into account the price of oil
and natural gas and well production volumes.




On
November 19, 2008 and November 24, 2008 the Alberta provincial government
announced details of an optional five year transitional royalty program that
applies to conventional oil and natural gas wells drilled to measured depths
between 1,000 to 3,500 meters between November 19, 2008 and January 1, 2014. For
each well, the Trust can make a one time election to produce the well under the
transitional royalty program or the new royalty regime. As of January 1, 2014,
all production subject to the transitional program will revert to the new
royalty regime.




On March
3, 2009, the Alberta provincial government announced an energy
incentive program to encourage activity in the conventional oil and gas sector
in Alberta.  The program includes provisions for (a) a drilling
royalty credit of $200 per meter drilled on new conventional oil and natural gas
wells on Crown lands that are drilled between April 1, 2009 and before
April 1, 2010 and (b) a maximum royalty rate of five (5) percent applicable
for 12 calendar months, 50,000 barrels of Crown production or 500 million cubic
feet, whichever is reached first, applicable to new wells on Crown lands that
begin producing conventional oil and natural gas between April 1, 2009 and March
31, 2010.




As part
of its "Energizing Investment" report issued on March 11, 2010, the Government
of Alberta announced that the royalty framework for natural gas and conventional
oil will be modified for all production effective as of January 1,
2011.  The modifications will include reducing the maximum royalty
rate for conventional oil and natural gas from 50 percent to 40 percent and 36
percent, respectively, and making the current maximum five percent front-end
rate on natural gas and conventional oil production a permanent feature of the
Alberta royalty regime.  In addition, the Government of Alberta is
currently engaged in additional analysis of the royalty regime applicable to
natural gas development and has indicated that the results of this analysis and
its impact on royalty rates applicable to natural gas production will be
announced prior to the end of May, 2010.




These
changes to the Alberta royalty regime, as well as the potential for changes in
the royalty regimes applicable in other provinces have created uncertainty
surrounding the ability to accurately estimate future royalties, resulting in
additional volatility and uncertainty for producers. See "Information Concerning
the Oil and Gas Industry - Provincial Royalties and Incentives".




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





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Natural
Gas Liquids Midstream Processing and Marketing Business Risk
Factors




Facilities
Throughput




The
volumes of natural gas processed through Provident's natural gas liquids
midstream 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.  Lower production volumes will also increase the
competition for natural gas supply at gas processing plants which could result
in higher shrinkage premiums being paid to natural gas producers.




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 liquids midstream processing and marketing business is connected to
various third party trunkline systems.  Operational disruptions or
apportionment on those third party systems may prevent the full utilization of
the business.




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




Operational
Matters and Hazards




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







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Operating
and Capital Costs




Operating
and capital costs of Provident's natural gas liquids midstream 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 liquids midstream 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 industriesto 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 liquids midstream
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 liquids midstream processing and
marketing business at the end of their economic life, which abandonment costs
may be substantial. It is not possible to estimate the abandonment costs at this
time as they will be a function of regulatory requirements at the time of
abandonment.





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Frac
Spread




The
MidstreamBusiness
is exposed to possible price declines between the time Provident purchases NGL
feedstock and sells NGL products, and to narrowing frac spreads.  Frac
spread is the difference between the selling prices for NGL products and the
input cost of the natural gas required to produce the respective NGL products.
The frac spread can change significantly from period to period depending on the
relationship between crude oil and natural gas prices (the "frac spread ratio"),
absolute commodity prices, and changes in the Canadian to U.S. dollar foreign
exchange rate.  There is also a differential between NGL product
prices and crude oil prices which can change prices received and margins
realized for midstream products separate from frac spread ratio
changes.  The amount of profit or loss made on the extraction portion
of the MidstreamBusiness will generally
increase or decrease with the frac spread. This exposure could result in
material variability of cash flow generated by the Midstream Business, which
could negatively affect the Trust and the cash distributions of the
Trust.




Reliance
on Principal Customers and Operators




Provident
will rely on several significant customers to purchase product from the
Midstream Business.  Ethane is predominately purchased by Nova
Chemicals Corporation and Dow Chemicals Canada Inc.  EnCana
Corporation and its affiliates ("EnCana") will purchase the majority of the
condensate from the EnCana Empress Debutanizer.  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 MidstreamBusiness could be
negatively impacted.




General
Risk Factors




Availability
of Credit and Debt Service




As of
March 18, 2010, the Trust had drawn $90.0 million against its credit
facility and had $31.6 million of the credit facility drawn on letters of
credit, representing 12 percent of the 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.




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.




The
weakened global economic situation in 2008 and 2009 restricted Provident's
access to capital, bank debt and equity, and resulted in increased borrowing
costs.  Provident's ability to finance future capital expenditures out
of funds generated from operations, borrowings and possible future equity sales
is dependent on, among other factors, the overall state of capital markets and
investor appetite for investments in the energy industry and the Trust's
securities in particular.  Although atentative recovery from
the global recession beginning in 2009 has led to improved economic conditions,
continued uncertainty has created ongoing fiscal challenges for the North
American economy which may alter Provident's spending and operating plans and
may continue to increase Provident's borrowing costs.  There may be
unexpected business impacts from this market uncertainty, including volatile
changes in currency exchange rates, inflation, interest rates, and general
levels of investing and consuming activity.





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-





To the
extent that external sources of capital become limited or unavailable or
available on onerous terms, the Trust's ability to make capital investments,
maintain existing assets and pay distributions may be impaired, and its assets,
liabilities, business, financial condition and results of operations may be
materially and adversely affected as a result.




Based on
current funds available and expected funds generated from operations, the Trust
believes it has sufficient funds available to fund its projected capital
expenditures. However, if funds generated from operations are lower than
expected or capital costs for these projects exceed current estimates, or if
Provident incurs major unanticipated expenses related to development or
maintenance of its existing properties, it may be required to seek additional
capital to maintain its capital expenditures at planned
levels.  Failure to obtain any financing necessary for Provident's
capital expenditure plans may result in a delay in development of Provident's
properties.




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".  There can be no
assurance that the treatment of mutual fund trusts will not be changed in a
manner which adversely affects Trust Unitholders.  See "Information
Concerning the Trust, PEL, PMHLP and Other Entities - Provident Energy Trust -
Limitation on Non-Resident Trust Unitholders" in this Annual Information
Form.




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




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




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




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




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





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-





Litigation
  The Trust
and its various subsidiaries and affiliates are, in the course of their
business, subject to lawsuits and other claims.  Defence and
settlement costs associated with such lawsuits and claims can be substantial,
even with respect to lawsuits and claims that have no merit.  Due to
the inherent uncertainty of the litigation process, the resolution of any
particular legal proceeding could have a material adverse effect on the
financial position or operating results of Provident.




Changes
in Legislation




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




Nature
of Trust Units




The Trust
Units do not represent a traditional investment in the oil and natural gas or
NGLs processing sectors and should not be viewed by investors as shares in the
Trust or other interests in the Trust's other entities.  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, the assets of the Midstream Business 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 Provident to acquire suitable energy related assets and to fund
distributions.  Changes in market conditions may adversely affect the
trading price of the Trust Units.




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




Redemption
Right




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




Unitholder
Limited Liability




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




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


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-





The
operations of Provident 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 PEL 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 PEL 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.




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 liquids midstream 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.




Variations
in the exchange rate for the Canadian dollar versus the U.S. dollar could result
in a significant change in the amount Provident receives on the sale of its
production, which may affect future distributions and the future value of
Provident'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.




INTERESTS
OF MANAGEMENT AND OTHERS IN MATERIAL TRANSACTIONS








- 54
-








TRANSFER
AGENT AND REGISTRAR




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




INTERESTS
OF EXPERTS




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




MATERIAL
CONTRACTS




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




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




DOCUMENTS
INCORPORATED BY REFERENCE




Any
statement contained in a document incorporated or deemed to be incorporated by
reference herein shall be deemed to be modified or superseded for the purposes
of this Annual Information Form to the extent that a statement contained herein,
or any other subsequently filed document which also is or is deemed to be
incorporated by reference herein, modifies or supersedes that
statement.  The modifying or superseding statement need not state that
it has modified or superseded a prior statement or include any other information
set forth in the document that is modified or superseded.  The making
of a modifying or superseding statement shall not be deemed an admission for any
purposes that the modified or superseded statement, when made, constituted a
misrepresentation, an untrue statement of a material fact or an omission to
state a material fact that is required to be stated or that is necessary to make
a statement not misleading in light of the circumstances in which it was
made.  Any statement so modified or superseded shall not be deemed,
except as so modified or superseded, to constitute a part of this Annual
Information Form.




The Trust
will provide without charge to each security holder to whom this Annual
Information Form is delivered, upon the written or oral request of such person
(and to each person who is not a security holder of the Trust upon payment of a
reasonable charge), a copy of any or all of the documents incorporated herein by
reference, other than exhibits to such documents (unless such exhibits are
specifically incorporated by reference into such documents).  Requests
for such documents should be directed to the office of Investor Relations,
Provident Energy Ltd., 2100, 250 - 2nd
Street S.W., Calgary, Alberta T2P 0C1, telephone: (403)
231-6710.  Documents incorporated by reference in this Annual
Information Form are also available on SEDAR at www.sedar.com.







- 55
-




PRINCIPAL
HOLDERS OF TRUST UNITS




As at the
date hereof, to the knowledge of Provident, no person or company owned of record
or beneficially, directly or indirectly, more than 10 percent of the issued and
outstanding Trust Units.  As at March 18, 2010,the directors and senior
officers of Provident, as a group, beneficially owned, directly or indirectly,
2,390,264 Trust Units or less than 1 percent of the issued and outstanding Trust
Units.




ADDITIONAL
INFORMATION




Additional
information related to the remuneration of the directors and officers of PEL,
the indebtedness of the directors and officers of PEL, 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 for its most recent annual meeting of
Unitholders that involved the election of directors.  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, 2009.




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






Lynn
Rannelli, Assistant Corporate Secretary


Provident
Energy Ltd.


2100, 250
– 2nd
Street S.W.


Calgary,
Alberta  T2P 0C1




Telephone:
            (403)
      296-2233Fax:
            (403)
      294-0111





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


- 56
-





SCHEDULE
A







Audit Committee Terms of
Reference




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




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




Composition




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




All
members of the Committee must satisfy the independence, financial literacy and
experience requirements of applicable Canadian and United States securities
laws, rules and guidelines, any applicable stock exchange requirements or
guidelines and any other applicable regulatory rules.  In particular:
(i) each member shall be "independent" and "financially literate" within
the meaning of National Instrument 52-110 - Audit Committees,
(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;







A-2





7.
            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.




8.
            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




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-3





(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







A-4





(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







A-5





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.







A-6





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.







A-7





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.








A-8







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




·
            Annual
      information form and comparable
40-F.




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




October/November
Meeting




·
            Discuss
      annual audit plan including scope of engagement and related matters 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.




A-9




·
            Review
      of complaints received and outcome of
  investigation.




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










A-10


Consolidated
financial highlights
 
 Consolidated
                  Three
      months ended December 31,
                  
                  
                  Year
      ended December 31,($
      000s except per unit data)2009
                  
                  
                  2008
                  
                  
                  %
      Change
                  
                  
                  2009
                  
                  
                  2008
                  
                  
                  %
      ChangeRevenue
      (net of royalties and financial derivative
                    instruments)
      from continuing operations
                  
                  $
                  469,359
                  
                  
                  $
                  1,019,320
                  
                  
                  
                  (54
                  )
                  
                  $
                  1,711,483
                  
                  
                  $
                  3,239,163
                  
                  
                  
                  (47
                  )Funds
      flow from Provident Upstream operations (1)
                  
                  $
                  20,882
                  
                  
                  $
                  47,187
                  
                  
                  
                  (56
                  )
                  
                  $
                  102,156
                  
                  
                  $
                  338,640
                  
                  
                  
                  (70
                  )Funds
      flow from Provident Midstream operations(1)
                  
                  
                  55,458
                  
                  
                  
                  34,592
                  
                  
                  
                  60
                  
                  
                  
                  161,850
                  
                  
                  
                  178,982
                  
                  
                  
                  (10
                  )Funds
      flow from continuing operations (1)
                  
                  $
                  76,340
                  
                  
                  $
                  81,779
                  
                  
                  
                  (7
                  )
                  
                  $
                  264,006
                  
                  
                  $
                  517,622
                  
                  
                  
                  (49
                  )Per
      weighted average unit – basic and diluted
                  
                  $
                  0.29
                  
                  
                  $
                  0.32
                  
                  
                  
                  (9
                  )
                  
                  $
                  1.01
                  
                  
                  $
                  2.03
                  
                  
                  
                  (50
                  )Distributions
      to unitholders
                  
                  $
                  47,456
                  
                  
                  $
                  77,324
                  
                  
                  
                  (39
                  )
                  
                  $
                  196,217
                  
                  
                  $
                  352,291
                  
                  
                  
                  (44
                  )Per
      unit
                  
                  $
                  0.18
                  
                  
                  $
                  0.30
                  
                  
                  
                  (40
                  )
                  
                  $
                  0.75
                  
                  
                  $
                  1.38
                  
                  
                  
                  (46
                  )Percent
      of funds flow from continuing operations
                    paid
      out as declared distributions
                  
                  
                  62
                  %
                  
                  
                  95
                  %
                  
                  
                  (35
                  )
                  
                  
                  74
                  %
                  
                  
                  68
                  %
                  
                  
                  9Net
      (loss) income
                  
                  $
                  (20,338
                  )
                  
                  $
                  (43,248
                  )
                  
                  
                  (53
                  )
                  
                  $
                  (89,020
                  )
                  
                  $
                  157,392
                  
                  
                  
                  -Per
      weighted average unit – basic and diluted
                  
                  $
                  (0.08
                  )
                  
                  $
                  (0.17
                  )
                  
                  
                  (53
                  )
                  
                  $
                  (0.34
                  )
                  
                  $
                  0.62
                  
                  
                  
                  -Capital
      expenditures (continuing operations)
                  
                  $
                  18,694
                  
                  
                  $
                  54,903
                  
                  
                  
                  (66
                  )
                  
                  $
                  127,369
                  
                  
                  $
                  246,947
                  
                  
                  
                  (48
                  )Acquisitions
      (continuing operations)
                  
                  $
                  56
                  
                  
                  $
                  4,632
                  
                  
                  
                  
                  
                  
                  $
                  18,833
                  
                  
                  $
                  25,843Proceeds
      on sale of assets (continuing operations) (2)
                  
                  $
                  84,097
                  
                  
                  $
                  38
                  
                  
                  
                  
                  
                  
                  $
                  322,720
                  
                  
                  $
                  1,662Proceeds
      on sale of discontinued operations,
                    net
      of tax
                  
                  $
                  -
                  
                  
                  $
                  19,044
                  
                  
                  
                  
                  
                  
                  $
                  -
                  
                  
                  $
                  457,906Weighted
      average trust units outstanding (000s)-
      basic and diluted (3)
                  
                  
                  263,482
                  
                  
                  
                  257,526
                  
                  
                  
                  2
                  
                  
                  
                  261,540
                  
                  
                  
                  255,177
                  
                  
                  
                  2
 
 
 
 ConsolidatedAs
      at December 31,($
      000s)
                  
                  2009
                  
                  
                  2008
                  
                  
                  %
      ChangeCapitalizationLong-term
      debt (including current portion)
                  
                  $
                  505,262
                  
                  
                  $
                  765,679
                  
                  
                  
                  (34
                  )Unitholders’
      equity
                  
                  $
                  1,381,399
                  
                  
                  $
                  1,636,347
                  
                  
                  
                  (16
                  )(1)
      Represents cash flow from continuing operations before changes in working
      capital and site restoration expenditures. Effective in the
      firstquarter
      of 2008, Provident's USOGP business was accounted for as discontinued
      operations.(2)Proceeds on sale of assets in 2009 include cash proceeds as well as
      $17.0 million of shares in Emerge Oil & Gas Inc. received on sale
      ofLloydminster
      properties.(3)Includes dilutive impact of unit options and convertible
      debentures.
  
 
 Operational
highlights
  Three
      months ended December 31,
                  
                  Year
      ended December 31,2009
                  
                  
                  2008
                  
                  
                  %
      Change
                  
                  
                  2009
                  
                  
                  2008
                  
                  
                  %
      ChangeOil
      and Gas Production - continuing operationsDaily
      production - Provident UpstreamCrude
      oil (bpd)
                  
                  
                  5,533
                  
                  
                  
                  12,307
                  
                  
                  
                  (55
                  )
                  
                  
                  8,875
                  
                  
                  
                  12,473
                  
                  
                  
                  (29
                  )Natural
      gas liquids (bpd)
                  
                  
                  1,072
                  
                  
                  
                  1,134
                  
                  
                  
                  (5
                  )
                  
                  
                  1,121
                  
                  
                  
                  1,203
                  
                  
                  
                  (7
                  )Natural
      gas (mcfd)
                  
                  
                  60,992
                  
                  
                  
                  80,450
                  
                  
                  
                  (24
                  )
                  
                  
                  69,575
                  
                  
                  
                  84,039
                  
                  
                  
                  (17
                  )Provident
      Upstream oil equivalent (boed) (1)
                  
                  
                  16,770
                  
                  
                  
                  26,849
                  
                  
                  
                  (38
                  )
                  
                  
                  21,592
                  
                  
                  
                  27,683
                  
                  
                  
                  (22
                  )Average
      realized price from continuing operations
                    (before
      realized financial derivative instruments)Crude
      oil blend ($/bbl)
                  
                  $
                  66.03
                  
                  
                  $
                  47.33
                  
                  
                  
                  40
                  
                  
                  $
                  54.15
                  
                  
                  $
                  82.79
                  
                  
                  
                  (35
                  )Natural
      gas liquids ($/bbl)
                  
                  $
                  59.25
                  
                  
                  $
                  47.64
                  
                  
                  
                  24
                  
                  
                  $
                  44.40
                  
                  
                  $
                  76.88
                  
                  
                  
                  (42
                  )Natural
      gas ($/mcf)
                  
                  $
                  4.36
                  
                  
                  $
                  6.63
                  
                  
                  
                  (34
                  )
                  
                  $
                  3.86
                  
                  
                  $
                  8.23
                  
                  
                  
                  (53
                  )Oil
      equivalent ($/boe) (1)
                  
                  $
                  41.42
                  
                  
                  $
                  43.58
                  
                  
                  
                  (5
                  )
                  
                  $
                  37.00
                  
                  
                  $
                  65.64
                  
                  
                  
                  (44
                  )Field
      netback from continuing operations(3) (before
                    realized
      financial derivative instruments) ($/boe)
                  
                  $
                  18.83
                  
                  
                  $
                  21.21
                  
                  
                  
                  (11
                  )
                  
                  $
                  16.57
                  
                  
                  $
                  39.85
                  
                  
                  
                  (58
                  )Field
      netback from continuing operations (3)  (including
                    realized
      financial derivative instruments) ($/boe)
                  
                  $
                  19.70
                  
                  
                  $
                  24.54
                  
                  
                  
                  (20
                  )
                  
                  $
                  18.65
                  
                  
                  $
                  38.75
                  
                  
                  
                  (52
                  )MidstreamProvident
      Midstream NGL sales volumes (bpd)
                  
                  
                  111,912
                  
                  
                  
                  120,222
                  
                  
                  
                  (7
                  )
                  
                  
                  113,528
                  
                  
                  
                  119,649
                  
                  
                  
                  (5
                  )Adjusted
      EBITDA (000s) (2)
                  
                  $
                  60,855
                  
                  
                  $
                  37,666
                  
                  
                  
                  62
                  
                  
                  $
                  182,317
                  
                  
                  $
                  212,761
                  
                  
                  
                  (14
                  )(1)Provident reports oil equivalent production converting natural gas
      to oil on a 6:1 basis.(2)Adjusted EBITDA is earnings before interest, taxes, depletion,
      depreciation, accretion and other non-cash items - see "Reconciliation of
      non-GAAP measures".(3)
      Field netback from continuing operations is a non-GAAP measure - see
      "Provident Upstream segment review - operating netback".
 
 
 
 
 Management’s
Discussion & Analysis
 
 The
following analysis provides a detailed explanation of Provident’s operating
results for the quarter and year ended December 31, 2009 compared to the quarter
and year ended December 31, 2008 and should be read in conjunction with the
consolidated financial statements of Provident. This analysis has been prepared
using information available up to March 11, 2010.
 
 Provident
Energy Trust has diversified investments in certain segments of the energy value
chain. Provident currently operates in two key business segments: Canadian crude
oil and natural gas production (“Provident Upstream”), and Provident
Midstream.  Provident’s Upstream business produces crude oil and
natural gas from four operating areas in the western Canadian sedimentary
basin.  During 2009, Provident completed the sale of Upstream
properties in Southeast Saskatchewan, Southwest Saskatchewan and
Lloydminster.  Subsequent to December 31, 2009, Provident sold the
Upstream properties in the West Central Alberta operating area, reducing
Provident’s Upstream activities to three operating areas, 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.  Effective in the first quarter of 2008,
Provident’s United States oil and natural gas production (“USOGP”) business was
accounted for as discontinued operations. The USOGP business was sold in
2008.
  This
analysis commences with a summary of the consolidated financial and operating
results followed by segmented reporting on the Upstream business unit and the
Midstream business unit.  The reporting focuses on the financial and
operating measurements management uses in making business decisions and
evaluating performance.
 
 This
analysis contains forward-looking information and statements.  See
“Forward-looking information” at the end of the analysis for further
discussion.
 
 The
analysis refers to certain financial and operational measures that are
determined to not be in accordance with generally accepted accounting principles
(GAAP) in Canada. These non-GAAP measures include funds flow from continuing
operations, adjusted EBITDA and operating netbacks.
 
 Management
uses funds flow from continuing operations to analyze operating
performance.  Funds flow from continuing operations is reviewed, along
with debt repayments and capital programs in setting monthly
distributions.  Funds flow from continuing operations as presented is
not intended to represent cash flow from operations or operating profits for the
period nor should it be viewed as an alternative to cash provided by operating
activities, net earnings or other measures of financial performance calculated
in accordance with Canadian GAAP. All references to funds flow from continuing
operations throughout this report are based on cash provided by operating
activities before changes in non-cash working capital, site restoration
expenditures and cash provided by operating activities from discontinued
operations. See “reconciliation of non-GAAP measures”.
 
 Management
uses adjusted EBITDA to analyze the operating performance of each business unit.
Adjusted 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. Adjusted EBITDA as presented is not
intended to represent cash provided by operating activities, net earnings or
other measures of financial performance calculated in accordance with Canadian
GAAP.  All references to adjusted EBITDA throughout this report are
based on earnings before interest, taxes, depletion, depreciation, accretion,
and other non-cash items (“adjusted EBITDA”). See “reconciliation of non-GAAP
measures”.
 
 Field
operating netback as presented does not have a standardized meaning prescribed
by Canadian GAAP and may not be comparable with calculations of similar measures
of other entities. See “Provident Upstream segment review- operating
netback”.
  
 
 
 Fourth quarter
highlights
 
 The
fourth quarter highlights section provides commentary on the fourth quarter of
2009 results compared to the fourth quarter of
2008.   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.
 
 Funds
flow from continuing operations and cash distributions
  Three
      months ended December 31,($
      000s, except per unit data)
                  
                  2009
                  
                  
                  2008
                  
                  
                  %
      ChangeFunds
      flow from continuing operations and DistributionsFunds
      flow from continuing operations
                  
                  $
                  76,340
                  
                  
                  $
                  81,779
                  
                  
                  
                  (7
                  )Per
      weighted average unit from continuing operations-
      basic and diluted (1)
                  
                  $
                  0.29
                  
                  
                  $
                  0.32
                  
                  
                  
                  (9
                  )Declared
      distributions
                  
                  $
                  47,456
                  
                  
                  $
                  77,324
                  
                  
                  
                  (39
                  )Per
      unit
                  
                  $
                  0.18
                  
                  
                  $
                  0.30
                  
                  
                  
                  (40
                  )Percent
      of funds flow from continuing
                    operations
      paid out as declared distributions
                  
                  
                  62
                  %
                  
                  
                  95
                  %
                  
                  
                  (35
                  )(1)Includes dilutive impact of unit options and convertible
      debentures.
  Fourth
quarter 2009 funds flow from continuing operations was $76.3 million, seven
percent below the $81.8 million recorded in the fourth quarter of
2008.  Provident Upstream’s 2009 fourth quarter funds flow from
operations was $20.9 million, a 56 percent decrease from the $47.2 million
recorded in the comparable 2008 quarter.  The lower Upstream funds
flow reflects strategic divestments in the Upstream business unit that closed in
the third and fourth quarters of 2009.
 
 The
Provident Midstream business unit added $55.4 million to fourth quarter 2009
funds flow from operations, 60 percent above the $34.6 million recorded in the
comparable 2008 quarter.  The Midstream business unit performance
reflects higher operating margins in the fourth quarter of 2009.  The
fourth quarter of 2009 Provident Midstream margins benefitted from a stronger
pricing environment than in the fourth quarter of 2008.
 
 Declared
distributions in the fourth quarter of 2009 totaled $47.5 million, 62 percent of
funds flow from continuing operations. This compares to $77.3 million of
declared distributions in fourth quarter of 2008, 95 percent of funds flow from
continuing operations.
 
 Net
loss
  Consolidated
                  
                  Three
      months ended December 31,($
      000s, except per unit data)
                  
                  2009
                  
                  
                  2008
                  
                  
                  %
      ChangeNet
      loss
                  
                  $
                  (20,338
                  )
                  
                  $
                  (43,248
                  )
                  
                  
                  (53
                  )Per
      weighted average unit–
      basic (1)and diluted(2)
                  
                  $
                  (0.08
                  )
                  
                  $
                  (0.17
                  )
                  
                  
                  (53
                  )(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 and
      convertible
                    debentures.
 
 In the
fourth quarter of 2009, Provident recorded a net loss of $20.3 million compared
to a loss of $43.2 million in the comparable 2008 quarter.
 
 The
Provident Upstream business segment net loss of $20.6 million, in the fourth
quarter of 2009 compared to a 2008 fourth quarter net loss of $421.5
million.  The majority of the 2008 fourth quarter net loss was due to
a non-cash goodwill impairment charge of $416.9 million.  The largest
contributors to the remaining quarter over quarter change were a $29.3 million
decrease in adjusted EBITDA and a $28.4 million reduction in unrealized gain
on
 
 
 
 financial
derivative instruments offset by lower DD&A and increased future income tax
recoveries.
 
 The
Provident Midstream segment had a net income of $0.3 million in the fourth
quarter of 2009, compared to $359.2 million in the fourth quarter of
2008.  Improved adjusted EBITDA of $60.9 million in the fourth quarter
of 2009 compared to $37.7 million in the fourth quarter of 2008 and a $64.8
million reduction in future tax expense were more than offset by a $415.7
million change in unrealized gains (losses) on financial derivative instruments
from a gain in the fourth quarter of 2008 of $377.7 million to a loss in the
fourth quarter of 2009 of $38.0 million.  In addition, a $12.4 million
intangible asset impairment charge was recorded in DD&A in the fourth
quarter of 2009.
 
 Provident’s
net income figures are affected by the requirement to “mark-to-market” all
financial derivative instruments at the end of the period and report these
unrealized gains or losses as part of current period net
income.  Because Provident’s commodity price risk management program
currently extends over three years into the future in the Midstream segment, net
earnings can show substantial quarterly variation that is not necessarily
related to current operations.
 
 Reconciliation
of non-GAAP measures
 
 The Trust
calculates earnings before interest, taxes, depletion, depreciation, accretion
and other non-cash items (adjusted EBITDA) within its segment disclosure.
Adjusted EBITDA is a non-GAAP measure.  A reconciliation between
adjusted EBITDA and loss from continuing operations before taxes
follows:
  Three
      months ended December 31,($
      000s)
                  
                  2009
                  
                  
                  2008
                  
                  
                  %
      ChangeLoss
      from continuing operations before taxes
                  
                  $
                  (46,013
                  )
                  
                  $
                  (13,880
                  )
                  
                  
                  232Adjusted
      for:Cash
      interest
                  
                  
                  5,613
                  
                  
                  
                  9,998
                  
                  
                  
                  (44
                  )Unrealized
      loss (gain) on financial derivative instruments
                  
                  
                  40,080
                  
                  
                  
                  (404,023
                  )
                  
                  
                  -Goodwill
      impairment
                  
                  
                  -
                  
                  
                  
                  416,890
                  
                  
                  
                  -Depletion,
      depreciation and accretion and other non-cash expenses
                  
                  
                  81,591
                  
                  
                  
                  78,438
                  
                  
                  
                  4Adjusted
      EBITDA
                  
                  $
                  81,271
                  
                  
                  $
                  87,423
                  
                  
                  
                  (7
                  )
 
  The
following table reconciles funds flow from continuing operations with cash
provided by operating activities:
  Reconciliation
      of funds flow from continuing operations
                  Three
      months ended December 31,($
      000s)
                  
                  2009
                  
                  
                  2008
                  
                  
                  %
      ChangeCash
      provided by operating activities
                  
                  $
                  92,692
                  
                  
                  $
                  150,032
                  
                  
                  
                  (38
                  )Change
      in non-cash operating working capital from continuing
      operations
                  
                  
                  (15,697
                  )
                  
                  
                  (70,677
                  )
                  
                  
                  (78
                  )Site
      restoration expenditures
                  
                  
                  (655
                  )
                  
                  
                  2,424
                  
                  
                  
                  (127
                  )Funds
      flow from continuing operations
                  
                  
                  76,340
                  
                  
                  
                  81,779
                  
                  
                  
                  (7
                  )
  Taxes
  Three
      months ended December 31,($
      000s)
                  
                  2009
                  
                  
                  2008
                  
                  
                  %
      ChangeCapital
      tax expense
                  
                  $
                  268
                  
                  
                  $
                  485
                  
                  
                  
                  (45
                  )Current
      tax expense (recovery)
                  
                  
                  1,198
                  
                  
                  
                  (4,453
                  )
                  
                  
                  -Future
      income tax (recovery) expense
                  
                  
                  (27,141
                  )
                  
                  
                  52,379
                  
                  
                  
                  -$
                  (25,675
                  )
                  
                  $
                  48,411
                  
                  
                  
                  -
  
  The
current tax expense was $1.2 million in the fourth quarter of 2009 compared to a
recovery in the fourth quarter of 2008 of $4.5 million.  The 2009
expense was driven by earnings in Provident’s Canadian Midstream business in
excess of allowed tax pool claims.  The recoveries in 2008 were driven
by lower earnings subject to tax in the US Midstream operations allowing the
recovery of taxes accrued or paid in prior periods.
 
 The 2009
fourth quarter future income tax recovery of $27.1 million compares to an
expense of $52.4 million in the fourth quarter of 2008.  The future
income tax recovery in the fourth quarter of 2009 was a result of losses created
by interest and royalty deductions at the incorporated subsidiary level as well
as the unrealized loss on financial derivative instruments. The future income
tax expense in the fourth quarter of 2008 resulted primarily from future taxes
calculated on the unrealized gains on financial derivative instruments while the
goodwill impairment charge was not tax affected.
 
 Interest
expense
  Continuing
      operations
                  
                  Three
      months ended December 31,($
      000s, except as noted)
                  
                  2009
                  
                  
                  2008
                  
                  
                  %
      ChangeInterest
      on bank debt
                  
                  $
                  1,567
                  
                  
                  $
                  5,015
                  
                  
                  
                  (69
                  )Interest
      on convertible debentures
                  
                  
                  4,046
                  
                  
                  
                  4,983
                  
                  
                  
                  (19
                  )Total
      cash interest
                  
                  $
                  5,613
                  
                  
                  $
                  9,998
                  
                  
                  
                  (44
                  )Weighted
      average interest rate on all long-term debt
                  
                  
                  3.6
                  %
                  
                  
                  5.1
                  %
                  
                  
                  (29
                  )Debenture
      accretion and other non-cash interest expense
                  
                  
                  1,091
                  
                  
                  
                  1,465
                  
                  
                  
                  (26
                  )Total
      interest expense
                  
                  $
                  6,704
                  
                  
                  $
                  11,463
                  
                  
                  
                  (42
                  )
  Interest
expense decreased for the quarter as compared to the same quarter in 2008 due to
significantly lower debt levels and lower market interest rates.  The
lower debt levels reflect the strategic asset dispositions that closed in the
third and fourth quarters of 2009.
 
 Commodity
price risk management program
 
 A summary
of Provident’s risk management contracts executed during the fourth quarter of
2009 is contained in the following tables.
 
 Activity
in the Fourth Quarter:
  MidstreamVolumeYear
                  Product
                  (Buy)/Sell
                  Terms
                  Effective
      Period2010
                  Crude
      Oil
                  (1,588)
      Bpd
                  US
      $77.75 per bbl (7)
                  January
      1 - March 31Propane
                  1,683
      Bpd
                  US
      $1.076 per gallon (4)
      (7)
                  January
      1 - March 311,695
      Bpd
                  US
      $1.155 per gallon(4)
      (8)
                  January
      1 - February 28Normal
      Butane
                  833
      Bpd
                  US
      $1.353 per gallon (5)
      (7)
                  January
      1 - March 31Electricity
                  (10)
      MW/hpd
                  Cdn
      $47.475 per MW/h (6)
                  January
      1 - December 312011
                  Natural
      Gas
                  (4,152)
      Gjpd
                  Cdn
      $7.33 per gj
                  January
      1 - December 31(1)The
      above table represents a number of transactions entered into over the
      fourth quarter 2009.(2)Natural
      gas contracts are settled agains AECO monthly index.(3)Crude
      Oil contracts are settled against NYMEX WTI calendar
    average.(4)Propane
      contracts are settled against Belvieu C3 TET.(5)Normal
      butane contracts are settled against Belvieu NC4 NON-TET.(6)Electricity
      contracts are settled against the hourly price of electricity as published
      by the AESO I $/MWh.(7)Conversion
      of Crude Oil BTU contracts to liquids.(8)Midstream
      inventory price stabilization contracts.
   
 
 Settlement
of commodity contracts
 
 The
following table summarizes the impact of financial derivative contracts settled
during the fourth quarters of 2009 and 2008 that were included in realized
(loss) gain on financial derivative instruments.
 
 Three
      months ended December 31,Realized
      (loss) gain on financial derivative instruments
                  
                  2009
                  
                  
                  
                  
                  
                  2008($
      000s except volumes)
                  
                  
                  
                  
                  Volume(1)
                  
                  
                  
                  
                  
                  Volume(1)Provident
      UpstreamCrude
      Oil
                  
                  $
                  326
                  
                  
                  
                  0.1
                  
                  
                  $
                  6,089
                  
                  
                  
                  0.4Natural
      gas
                  
                  
                  1,017
                  
                  
                  
                  2.1
                  
                  
                  
                  2,130
                  
                  
                  
                  1.9Provident
      MidstreamCrude
      Oil
                  
                  
                  (5,630
                  )
                  
                  
                  1.0
                  
                  
                  
                  (4,123
                  )
                  
                  
                  1.3Natural
      gas
                  
                  
                  (21,333
                  )
                  
                  
                  5.4
                  
                  
                  
                  (13,046
                  )
                  
                  
                  6.7NGL's
      (includes propane, butane)
                  
                  
                  (1,729
                  )
                  
                  
                  0.4
                  
                  
                  
                  34,203
                  
                  
                  
                  0.2Foreign
      Exchange
                  
                  
                  1,045
                  
                  
                  
                  -
                  
                  
                  
                  (1,763
                  )
                  
                  
                  -Electricity
                  
                  
                  (188
                  )
                  
                  
                  -
                  
                  
                  
                  827
                  
                  
                  
                  -CorporateInterest
      Rate (2)
                  
                  
                  (545
                  )
                  
                  
                  -
                  
                  
                  
                  -
                  
                  
                  
                  -Realized
      (loss) gain on financial derivative instruments
                  
                  $
                  (27,037
                  )
                  
                  
                  
                  
                  
                  $
                  24,317
                  
                  
                  
                  -(1)
      The above table represents aggregate net volumes that were bought/sold
      over the periods. Crude oil and NGL volumes are listed
in
                    millions
      of barrels and natural gas is listed in millions of
      gigajoules.(2)
      Realized gains and losses on croporate related interest rate contracts are
      allocated to the reporting segments for segmented reporting
      purposes.
 
 The
realized loss for the fourth quarter of 2009 was $27.0 million compared to a
realized gain of $24.3 million in the comparable 2008 quarter.  The
realized loss in the fourth quarter of 2009 was driven by natural gas derivative
purchase contracts in the midstream business settling at a contracted price
higher than the current market gas prices.  The comparable 2008
realized gain was driven mostly by NGL derivative sales contracts in the
midstream business settling at contracted NGL prices higher than the NGL’s
market prices during the settlement period.
 
 In
addition, the Trust recorded a loss of $17 thousand (2008 - $21.6 million gain)
on corporate foreign exchange contracts.  The amounts were included in
foreign exchange loss (gain) and other on the consolidated statement of
operations and were allocated to the reporting segments.
 
 
 
 Provident
Upstream segment review
 
 Upstream
asset dispositions
 
 On
November 30, 2009, Provident closed the sale of its predominately heavy oil
assets in the Lloydminster operating area to a private company, Emerge Oil &
Gas Inc. for total consideration of $84.0 million, consisting of $67.0 million
in cash and $17.0 million in equity.  Net disposition proceeds were
applied to Provident’s revolving term credit facility.  Production on
the date the disposition was announced was approximately 2,200
boed.
 
 On
December 23, 2009, Provident announced that it had reached an agreement with
Storm Ventures International Inc. to sell the oil and natural gas assets in the
West Central Alberta operating area.  Production on the date of
announcement for these properties totaled approximately 5,000
boed.  The transaction closed on March 1,
2010.   Proceeds from the transaction of $177 million were
applied to Provident’s revolving term credit facility.
 
 Crude
oil and natural gas liquids prices
 
 The
following prices are net of transportation expense.
  Provident
      Upstream
                  
                  Three
      months ended December 31,($
      per bbl)
                  
                  2009
                  
                  
                  2008
                  
                  
                  %
      ChangeOil
      per barrelWTI
      (US$)
                  
                  $
                  76.19
                  
                  
                  $
                  58.73
                  
                  
                  
                  30Exchange
      rate (from US$ to Cdn$)
                  
                  
                  1.06
                  
                  
                  
                  1.21
                  
                  
                  
                  (12
                  )WTI
      expressed in Cdn$
                  
                  $
                  80.48
                  
                  
                  $
                  71.21
                  
                  
                  
                  13Realized
      pricing before financial derivative instrumentsCrude
      oil
                  
                  $
                  66.03
                  
                  
                  $
                  47.33
                  
                  
                  
                  40Natural
      gas liquids
                  
                  $
                  59.25
                  
                  
                  $
                  47.64
                  
                  
                  
                  24Crude
      oil and natural gas liquids
                  
                  $
                  64.93
                  
                  
                  $
                  47.36
                  
                  
                  
                  37
  In the
fourth quarter of 2009, Provident’s realized oil and natural gas liquids price,
prior to the impact of financial derivative instruments, increased by 37 percent
to $64.93 per barrel compared to $47.36 per barrel in the fourth quarter of
2008.  The increase was related to narrower differentials and a 30
percent higher US$ WTI crude oil price partially offset by a stronger Canadian
dollar.
 
 Natural
gas price
 
 The
following prices are net of transportation expense.
  Provident
      Upstream
                  
                  Three
      months ended December 31,(Cdn$
      per mcf)
                  
                  2009
                  
                  
                  2008
                  
                  
                  %
      ChangeAECO
      monthly index
                  
                  $
                  4.23
                  
                  
                  $
                  6.78
                  
                  
                  
                  (38
                  )Corporate
      natural gas price per mcf before
                    financial
      derivative instruments
                  
                  $
                  4.36
                  
                  
                  $
                  6.63
                  
                  
                  
                  (34
                  )
 
 Provident’s
fourth quarter 2009 realized natural gas price, prior to the impact of financial
derivative instruments, decreased 34 percent as compared to the fourth quarter
of 2008.  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 price can
therefore differ from benchmark indices.
 
  
 
 Production
  Provident
      Upstream
                  
                  Three
      months ended December 31,2009
                  
                  
                  2008
                  
                  
                  %
      ChangeDaily
      productionCrude
      oil (bpd)
                  
                  
                  5,533
                  
                  
                  
                  12,307
                  
                  
                  
                  (55
                  )Natural
      gas liquids (bpd)
                  
                  
                  1,072
                  
                  
                  
                  1,134
                  
                  
                  
                  (5
                  )Natural
      gas (mcfd)
                  
                  
                  60,992
                  
                  
                  
                  80,450
                  
                  
                  
                  (24
                  )Oil
      equivalent (boed) (1)
                  
                  
                  16,770
                  
                  
                  
                  26,849
                  
                  
                  
                  (38
                  )(1)
      Provident reports equivalent production converting natural gas to oil on a
      6:1 basis.
  Production
decreased 38 percent to 16,770 boed during the fourth quarter of 2009 as
compared to 26,849 boed in the comparable quarter of 2008.  The
decrease reflects approximately 4,000 boed of production sold prior to the start
of the fourth quarter of 2009 and the sale of approximately 2,200 boed of
predominately heavy oil production that closed on November 30,
2009.  The reduced volumes in the remaining core areas were impacted
by lower capital expenditures in 2009 on drilling and optimization activities as
well as capital directed at longer term plays that did not result in immediate
production additions.  The result was that production additions did
not offset the natural production declines.
 
 In the
third quarter of 2009, Provident reported the impact a third party natural gas
pipeline outage was having on the deliverability of its Northwest Alberta
natural gas production.  In the fourth quarter of 2009, operational
steps carried out by Provident resulted in nearly full deliverability of the
natural gas.  Provident has received indication from the third party
operator that repairs on this line should be completed prior to the end of the
first quarter of 2010.
 
 In
Dixonville, three more crude oil wells were converted to water injectors in the
fourth quarter as part of the phase one expansion, bringing the total wells
converted to 21 in 2009.  Production from these wells in the fourth
quarter of 2008 was approximately 500 bpd.  The approval for the phase
two expansion was received in January 2010 and an application for phase three
was submitted in February 2010.  Production growth in Dixonville is
expected to increase as the waterflood matures with incremental production
expected gradually over the next 18 months.
 
 Production
for the fourth quarter of 2009 was weighted 61 percent natural gas, and 39
percent crude oil and natural gas liquids.  This compared to fourth
quarter 2008 production weighted 50 percent natural gas and 50 percent crude oil
and natural gas liquids.
 
 Provident
Upstream’s production summarized by operating areas is as follows:
  Three
      months ended December 31,Provident
      Upstream
                  
                  2009
                  
                  
                  2008
                  
                  
                  %
      ChangeDaily
      Production - by area (boed) (1)West
      Central Alberta
                  
                  
                  4,931
                  
                  
                  
                  6,005
                  
                  
                  
                  (18
                  )Southern
      Alberta
                  
                  
                  4,449
                  
                  
                  
                  4,990
                  
                  
                  
                  (11
                  )Northwest
      Alberta
                  
                  
                  3,664
                  
                  
                  
                  4,283
                  
                  
                  
                  (14
                  )Dixonville
                  
                  
                  2,297
                  
                  
                  
                  3,750
                  
                  
                  
                  (39
                  )15,341
                  
                  
                  
                  19,028
                  
                  
                  
                  (19
                  )Other(2)
                  
                  
                  1,429
                  
                  
                  
                  7,821
                  
                  
                  
                  (82
                  )16,770
                  
                  
                  
                  26,849
                  
                  
                  
                  (38
                  )(1)
      Provident reports equivalent production converting natural gas to oil on a
      6:1 basis.(2)
      Includes Southeast Saskatchewan and Southwest Saskatchewan operating areas
      that were sold on September 30, 2009 and
                    Lloydminster
      operating area that was sold on November 30, 2009.
  
 
 
 Revenue
and royalties
   Provident
      Upstream
                  
                  Three
      months ended December 31,($
      000s except per boe and mcf data)
                  
                  2009
                  
                  
                  2008
                  
                  
                  %ChangeOilRevenue
                  
                  $
                  33,613
                  
                  
                  $
                  53,592
                  
                  
                  
                  (37
                  )Realized
      gain on financial derivative instruments
                  
                  
                  326
                  
                  
                  
                  6,089
                  
                  
                  
                  (95
                  )Royalties
                  
                  
                  (6,808
                  )
                  
                  
                  (9,159
                  )
                  
                  
                  (26
                  )Net
      revenue
                  
                  $
                  27,131
                  
                  
                  $
                  50,522
                  
                  
                  
                  (46
                  )Net
      revenue (per barrel)
                  
                  $
                  53.30
                  
                  
                  $
                  44.62
                  
                  
                  
                  19Royalties
      as a percentage of revenue
                  
                  
                  20.3
                  %
                  
                  
                  17.1
                  %Natural
      gasRevenue
                  
                  $
                  24,458
                  
                  
                  $
                  49,088
                  
                  
                  
                  (50
                  )Realized
      gain on financial derivative instruments
                  
                  
                  1,017
                  
                  
                  
                  2,130
                  
                  
                  
                  (52
                  )Royalties
                  
                  
                  (1,568
                  )
                  
                  
                  (7,643
                  )
                  
                  
                  (79
                  )Net
      revenue
                  
                  $
                  23,907
                  
                  
                  $
                  43,575
                  
                  
                  
                  (45
                  )Net
      revenue (per mcf)
                  
                  $
                  4.26
                  
                  
                  $
                  5.89
                  
                  
                  
                  (28
                  )Royalties
      as a percentage of revenue
                  
                  
                  6.4
                  %
                  
                  
                  15.6
                  %Natural
      gas liquidsRevenue
                  
                  $
                  5,841
                  
                  
                  $
                  4,970
                  
                  
                  
                  18Royalties
                  
                  
                  (1,599
                  )
                  
                  
                  (1,299
                  )
                  
                  
                  23Net
      revenue
                  
                  $
                  4,242
                  
                  
                  $
                  3,671
                  
                  
                  
                  16Net
      revenue (per barrel)
                  
                  $
                  43.01
                  
                  
                  $
                  35.19
                  
                  
                  
                  22Royalties
      as a percentage of revenue
                  
                  
                  27.4
                  %
                  
                  
                  26.1
                  %TotalRevenue
                  
                  $
                  63,912
                  
                  
                  $
                  107,650
                  
                  
                  
                  (41
                  )Realized
      gain on financial derivative instruments
                  
                  
                  1,343
                  
                  
                  
                  8,219
                  
                  
                  
                  (84
                  )Royalties
                  
                  
                  (9,975
                  )
                  
                  
                  (18,101
                  )
                  
                  
                  (45
                  )Net
      revenue
                  
                  $
                  55,280
                  
                  
                  $
                  97,768
                  
                  
                  
                  (43
                  )Net
      revenue (per boe)
                  
                  $
                  35.83
                  
                  
                  $
                  39.58
                  
                  
                  
                  (9
                  )Royalties
      as a percentage of revenue
                  
                  
                  15.6
                  %
                  
                  
                  16.8
                  %Note: the
      above revenue, net revenue and net revenue per boe figures are presented
      net of transportation expenses and the realized gain (loss) on financial
      derivative instruments excludes the impact of corporate interest rate swap
      gains/losses allocated to Provident Upstream.
  In the
fourth quarter of 2009, Provident Upstream production revenue was $63.9 million,
a decrease of 41 percent from $107.7 million in 2008.  A 38 percent
decrease in production and a 34 percent decrease in realized natural gas price,
partially offset by a 37 percent increase in crude oil and natural gas liquids
prices accounts for the change.  Royalties, which are price sensitive
and affected by production rates, decreased as a percentage of revenue mainly
due to significantly lower natural gas prices.  The preceding factors,
as well as the $6.9 million decrease in realized gain on financial derivative
instruments account for net revenue of $55.3 million in the fourth quarter of
2009, 43 percent below the $97.8 million recorded in the fourth quarter of
2008.  Net revenue per boe in the fourth quarter of 2009 was $35.83
per boe, a decrease of nine percent from $39.58 per boe in the fourth quarter of
2008.
  
 Production
expenses
  Provident
      Upstream
                  
                  Three
      months ended December 31,($
      000s, except per boe data)
                  
                  2009
                  
                  
                  2008
                  
                  
                  %
      ChangeProduction
      expenses
                  
                  $
                  24,889
                  
                  
                  $
                  37,159
                  
                  
                  
                  (33
                  )Production
      expenses (per boe)
                  
                  $
                  16.13
                  
                  
                  $
                  15.04
                  
                  
                  
                  7
 Fourth
quarter 2009 production expenses decreased 33 percent to $24.9 million from
$37.2 million in the comparable 2008 quarter.  The decrease was
primarily due to the disposition of approximately 4,000 boed of production in
the Southeast and Southwest Saskatchewan operating areas on September 30, 2009
and approximately 2,200 boed in the Lloydminster area on November 30,
2009.  On a per boe basis, quarter over quarter production expenses
increased by seven percent to $16.13 per boe from $15.04 per boe in the
comparable 2008 quarter.  The operating cost per boe increase in the
remaining core areas recognize fixed costs being allocated over fewer produced
barrels of oil equivalent.
 
 Operating
netback
 
 Operating
netback as presented does not have any standardized meaning prescribed by
Canadian generally accepted accounting principles (GAAP) and may not be
comparable with calculations of similar measures of other entities.
  Provident
      Upstream
                  
                  Three
      months ended December 31,($
      per boe)
                  
                  2009
                  
                  
                  2008
                  
                  
                  %
      ChangeNetback
      per boeGross
      production revenue
                  
                  $
                  41.42
                  
                  
                  $
                  43.58
                  
                  
                  
                  (5
                  )Royalties
                  
                  
                  (6.46
                  )
                  
                  
                  (7.33
                  )
                  
                  
                  (12
                  )Operating
      costs
                  
                  
                  (16.13
                  )
                  
                  
                  (15.04
                  )
                  
                  
                  7Field
      operating netback
                  
                  
                  18.83
                  
                  
                  
                  21.21
                  
                  
                  
                  (11
                  )Realized
      gain on financial derivative instruments
                  
                  
                  0.87
                  
                  
                  
                  3.33
                  
                  
                  
                  (74
                  )Operating
      netback after realized financial derivative instruments
                  
                  $
                  19.70
                  
                  
                  $
                  24.54
                  
                  
                  
                  (20
                  )
 
  Provident
Upstream operating netbacks have transportation expense netted against gross
production revenue.
  The
fourth quarter 2009 field operating netback decreased 11 percent to $18.83 per
boe from $21.21 per boe in the comparable quarter in 2008.  The five
percent drop in gross production revenue per boe reflects both the 34 percent
decrease in natural gas prices combined with Provident’s increased weighting of
natural gas production to 61 percent of the production base from 50 percent in
the comparable quarter in 2008.  Royalties, which are price sensitive,
decreased 12 percent on a per boe basis reflecting the significantly lower
natural gas prices.  The fourth quarter 2009 operating netback after
financial derivative instruments decreased by 20 percent to $19.70 per boe from
$24.54 per boe reflecting the preceding factors as well as the 2009 fourth
quarter gain on financial derivative instruments of $0.87 per boe compared to
$3.33 per boe in the comparable quarter in 2008.
 
 General
and administrative
  Provident
      Upstream
                  
                  Three
      months ended December 31,($
      000s, except per boe data)
                  
                  2009
                  
                  
                  2008
                  
                  
                  %
      ChangeCash
      general and administrative
                  
                  $
                  5,371
                  
                  
                  $
                  7,472
                  
                  
                  
                  (28
                  )Non-cash
      unit based compensation
                  
                  
                  2,774
                  
                  
                  
                  (3,040
                  )
                  
                  
                  -$
                  8,145
                  
                  
                  $
                  4,432
                  
                  
                  
                  84Cash
      general and administrative (per boe)
                  
                  $
                  3.48
                  
                  
                  $
                  3.02
                  
                  
                  
                  15
 
 
 
 Cash
general and administrative expenses for Provident Upstream in the fourth quarter
decreased 28 percent to $5.4 million from $7.5 million recorded in the 2008
comparable quarter.  On a per boe basis the cash general and
administrative expenses recorded in fourth quarter 2009 increased 15 percent to
$3.48 from $3.02 in the fourth quarter of 2008.  The decrease in total
cash general and administrative expense reflects staff reductions and cost
cutting measures implemented within the organization.  The increase in
the per boe amount is attributable to the reduced production that has been
impacted by the asset dispositions and production declines that reflect the
reduced capital program.
 
 The
non-cash unit based compensation was an expense of $2.8 million in the fourth
quarter of 2009 contrasts with a $3.0 million decrease in the expense in the
fourth quarter of 2008.  The 2009 expense and the 2008 reduction were
due primarily to changes in Provident Trust unit trading prices at the end of
the respective periods.  In 2009, the trust unit price was on an
upward trend in the fourth quarter compared to a downward trend in the
comparable 2008 quarter.
 
 Capital
expenditures
  Provident
      Upstream
                  
                  Three
      months ended December 31,($
      000s)
                  
                  2009
                  
                  
                  2008Capital
      expenditures - by categoryGeological,
      geophysical and land
                  
                  $
                  476
                  
                  
                  $
                  7,055Drilling
      and recompletions
                  
                  
                  8,264
                  
                  
                  
                  28,763Facilities
      and equipment
                  
                  
                  4,533
                  
                  
                  
                  10,682Office
      and other
                  
                  
                  150
                  
                  
                  
                  (4,067
                  )Total
      additions
                  
                  $
                  13,423
                  
                  
                  $
                  42,433Capital
      expenditures - by areaWest
      central Alberta
                  
                  $
                  1,223
                  
                  
                  $
                  3,383Southern
      Alberta
                  
                  
                  1,821
                  
                  
                  
                  6,113Northwest
      Alberta
                  
                  
                  3,049
                  
                  
                  
                  22,561Dixonville
                  
                  
                  6,681
                  
                  
                  
                  7,291$
                  12,774
                  
                  
                  $
                  39,348Other(1)
                  
                  
                  649
                  
                  
                  
                  3,085Total
      additions
                  
                  $
                  13,423
                  
                  
                  $
                  42,433Property
      acquisitions
                  
                  $
                  56
                  
                  
                  $
                  4,632Property
      dispositions(2)
                  
                  $
                  84,097
                  
                  
                  $
                  38(1)Includes Southeast Saskatchewan and Southwest Saskatchewan
      operating areas that were sold on September 30, 2009 andLloydminster
      operating area that was sold on November 30, 2009.(2)Property dispositions include cash proceeds on sale of assets as
      well as $17.0 million of shares in Emerge Oil & Gas
      Inc.received
      on sale of Lloydminster properties.
  In the
fourth quarter of 2009, Provident Upstream successfully executed its capital
program by spending $12.8 million on its four operating areas.  In
Dixonville, the waterflood enhanced oil recovery program is proceeding as
planned with fourth quarter spending of $6.7 million on facility expansion and
upgrade activities related to the conversion of the crude oil producing wells
into water injectors.  In Northwest Alberta, $3.1 million was
primarily spent on equipment and facility work associated with the start up of
the 2009/2010 winter drilling program, directed towards the emerging Pekisko
opportunity.  The $3.0 million of capital spent in the Southern and
West Central Alberta included 1.3 net wells drilled and ongoing completion,
tie-ins, recompletions, facility upgrades and production optimization
activities.  In addition $0.6 million was spent on other non-core
operating areas and corporate assets.
 
 
 
 
 Depletion,
depreciation and accretion (DD&A)
  Provident
      Upstream
                  
                  Three
      months ended December 31,($
      000s, except per boe data)
                  
                  2009
                  
                  
                  2008
                  
                  
                  %
      ChangeDD&A
                  
                  $
                  51,604
                  
                  
                  $
                  76,527
                  
                  
                  
                  (33
                  )DD&A
      (per boe)
                  
                  $
                  33.45
                  
                  
                  $
                  30.98
                  
                  
                  
                  8
 
 DD&A
charges in the fourth quarter of 2009 were down 33 percent to $51.6 million
compared to $76.5 million in the fourth quarter of 2008.  The lower
charges reflect a 38 percent decrease in production volumes in the fourth
quarter of 2009 compared to the fourth quarter of 2008.  This was
partially offset by an eight percent increase in the per boe rate of $33.45 per
boe for the fourth quarter of 2009 compared to $30.98 per boe for the fourth
quarter of 2008.  The per boe increase was primarily a result of 2008
and 2009 capital expenditures on longer term projects at Dixonville and the
Pekisko play in Northwest Alberta.  In the short term, these
expenditures add costs to the depletable base without the addition of further
proved reserves.  The addition of more proved reserves associated with
these projects would have a favorable impact on DD&A per boe.
 
 Accretion
expense associated with asset retirement obligations was $0.8 million in the
fourth quarter of 2009 compared to $0.9 million in the fourth quarter of
2008.
 
 
 
 Provident
Midstream business segment review
 
 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:
  Empress
East
 Redwater
West
 Commercial
Services
 
 Market
environment
 
 Performance
of the Midstream business unit is closely tied to market prices for NGL products
and natural gas, which can vary significantly from period to
period.  The key reference prices impacting Midstream operating
margins are summarized in the following table:
  Midstream
      business reference prices
                  
                  Three
      months ended December 31,2009
                  
                  
                  2008
                  
                  
                  %
      ChangeWTI
      (US$ per barrel)
                  
                  $
                  76.19
                  
                  
                  $
                  58.73
                  
                  
                  
                  30Exchange
      rate (from US$ to Cdn$)
                  
                  
                  1.06
                  
                  
                  
                  1.21
                  
                  
                  
                  (12
                  )WTI
      expressed in Cdn$ per barrel
                  
                  $
                  80.48
                  
                  
                  $
                  71.21
                  
                  
                  
                  13AECO
      monthly index (Cdn$ per gj)
                  
                  $
                  4.01
                  
                  
                  $
                  6.43
                  
                  
                  
                  (38
                  )Frac
      Spread Ratio (1)
                  
                  
                  20.1
                  
                  
                  
                  11.1
                  
                  
                  
                  81Mont
      Belvieu Propane (US$ per US gallon)
                  
                  $
                  1.09
                  
                  
                  $
                  0.80
                  
                  
                  
                  36Mont
      Belvieu Propane expressed as a percentage of WTI
                  
                  
                  60
                  %
                  
                  
                  57
                  %
                  
                  
                  5Market
      Frac Spread in Cdn$ per barrel (2)
                  
                  $
                  37.51
                  
                  
                  $
                  16.34
                  
                  
                  
                  1301)Frac spread ratio is the ratio of WTI expressed in Canadian dollars
      per barrel to the AECO monthly index (Cdn$ per gj).2) Market
      frac spread is determined using weighted average spot prices at Mont
      Belvieu for propane, butane, and condensate
                    and
      the AECO monthly index price for natural gas.
  The NGL
pricing environment has improved in recent months, and is significantly stronger
than in the fourth quarter of 2008. The average fourth quarter 2009 WTI crude
oil price of US$76.19 per barrel strengthened by approximately 12 percent
relative to the third quarter of 2009.  In contrast, as a result of
the weakening economy, during 2008 the WTI price fell by 50 percent to US$58.73
per barrel from the third to fourth quarter.  As oil prices are highly
correlated with NGL product prices, a rapid decline in the WTI price can have
significant impact on margins as NGL product inventories which are built in a
stronger pricing environment are then sold into a lower priced
market.  Conversely, a period of increasing WTI prices can have a
positive effect on margins. Propane prices as a percentage of WTI crude have
also improved over the last several months, increasing from lows of under 50
percent during the 2009 summer months to an average of 60 percent in the fourth
quarter of 2009.  Propane prices as a percentage of WTI are also
stronger relative the prior year quarter which averaged 57
percent.  As a result of higher crude oil prices and higher propane
prices relative to WTI, the 2009 fourth quarter Mont Belvieu propane price
averaged US$1.09 per US gallon, a 36 percent increase over the fourth quarter of
2008.  The stronger propane percentages relative to WTI experienced in
the fourth quarter of 2009 have continued into the first quarter of 2010 with
Mont Belvieu propane trading at an average of 71 percent of WTI during the
months of January and February.
  
 Natural
gas prices also strengthened over the fourth quarter of 2009, however prices
were still significantly lower than in the prior year. AECO natural gas averaged
$4.01 per gj in the fourth quarter of 2009 compared to $6.43 per gj during the
fourth quarter of 2008.  While lower natural gas prices are generally
favorable to NGL extraction and fractionation economics, a sustained period in a
low price environment could have an impact on the availability and overall cost
of natural gas and NGL mix supply in western Canada, if natural gas producers
elect to shut-in production or reduce drilling activities.
 
 Market
frac spreads increased to an average of $37.51 per barrel during the fourth
quarter of 2009.  Market frac spreads were also significantly higher
than the prior year quarter where a sharp decline in NGL product prices and
higher relative natural gas prices reduced market frac spreads to $16.34 per
barrel. The benefit of these higher market frac spreads to Provident was
tempered by the increased cost of purchasing natural gas supply in western
Canada, particularly at Empress.  Over the past several months Empress
extraction premiums have significantly increased as a result of reduced volumes
of natural gas flowing past the Empress straddle plants.  In the
fourth quarter of 2009, natural gas throughput at the Empress Eastern border
averaged approximately 4.4 bcf per day, a decrease of approximately 27 percent
compared to the same period in 2008.  While extraction premiums have
been excluded from the calculation of market frac spreads, they are included,
along with other costs, when determining actual extraction operating
margins.  Lower natural gas throughput at the Empress facilities
reduced propane-plus inventories currently available for sale in Sarnia and in
surrounding eastern markets.  In 2010, as available propane-plus
supply tightens relative to demand, pricing differentials in these eastern
markets where Provident sells the majority of its Empress East production, may
increase relative to other major propane hubs including Mont Belvieu and
Conway.
 
 At the
end of 2009, industry propane inventories in the United States were
approximately 49 million barrels, a decrease of 11 percent compared to the prior
year, and approximately seven million barrels below the five year historical
average.  United States propane inventories have fallen significantly
from a high of approximately 75 million barrels at the end of September 2009
when inventories exceeded the five year historical average by approximately 10
million barrels, driven by above average propane withdrawals during the fourth
quarter of 2009 which represent the first months of the winter heating
season.  Ending 2009 Canadian industry propane inventories of
approximately five million barrels were in-line with the prior year, but lower
than the five year average of approximately six million barrels.
 
 Midstream
business performance
 
 Midstream
business unit results can be summarized as follows:
  Three
      months ended December 31,(bpd)
                    
                    2009
                    
                    
                    2008
                    
                    
                    %
      ChangeProvident
      Midstream NGL sales volumes
                    
                    
                    111,912
                    
                    
                    
                    120,222
                    
                    
                    
                    (7
                    )
 Three
      months ended December 31,($
      000s)
                  
                  2009
                  
                  
                  2008
                  
                  
                  %
      ChangeEmpress
      East margin
                  
                  $
                  32,522
                  
                  
                  $
                  900
                  
                  
                  
                  3,514Redwater
      West margin
                  
                  
                  45,518
                  
                  
                  
                  4,142
                  
                  
                  
                  999Commercial
      Services margin
                  
                  
                  18,596
                  
                  
                  
                  12,095
                  
                  
                  
                  54Gross
      operating margin
                  
                  
                  96,636
                  
                  
                  
                  17,137
                  
                  
                  
                  464Realized
      (loss) gain on financial derivative instruments
                  
                  
                  (28,244
                  )
                  
                  
                  16,098
                  
                  
                  
                  -Cash
      general and administrative expenses
                  
                  
                  (6,229
                  )
                  
                  
                  (7,380
                  )
                  
                  
                  (16
                  )Strategic
      review and restructuring expenses
                  
                  
                  (217
                  )
                  
                  
                  (1,038
                  )
                  
                  
                  (79
                  )Foreign
      exchange (loss) gain and other
                  
                  
                  (1,091
                  )
                  
                  
                  12,849
                  
                  
                  
                  -Provident
      Midstream Adjusted EBITDA
                  
                  $
                  60,855
                  
                  
                  $
                  37,666
                  
                  
                  
                  62
   
 
 
 Gross
operating margin
 
 Midstream
gross operating margin during the fourth quarter of 2009 was very strong,
totaling $96.6 million, an increase of $79.5 million compared to the same period
in 2008.  The increase was predominantly due to significantly higher
propane-plus per unit margins realized in both the Empress East and Redwater
West business lines, partially offset by a seven percent reduction in NGL sales
volumes.  A higher contribution from the Commercial Services business
line has also increased gross operating margin in the fourth quarter of 2009
relative to the prior year.
 
 The
Empress East business line:
 
 The
Empress East business line extracts NGLs from natural gas at the Empress
straddle plants and sells finished products into markets in central Canada and
the eastern United States.  Demand for propane is seasonal and results
in inventory that generally builds over the second and third quarters of the
year and is sold in the fourth quarter and the first quarter of the following
year.  The margin in this business is determined primarily by the
“frac spread”, which represents the difference between the selling prices for
propane-plus and the input cost of the natural gas required to produce the
respective NGL products.  The frac spread can change significantly
from period to period depending on the relationship between crude oil and
natural gas prices (the “frac spread ratio”), absolute commodity prices, and
changes in the Canadian to US dollar foreign exchange
rate.  Traditionally a higher frac spread ratio and higher crude oil
prices will result in stronger business line margins.  Differentials
between propane-plus and crude oil prices, as well as locational price
differentials will also impact the frac spread.  Natural gas
extraction premiums and costs relating to transportation, fractionation, storage
and marketing are not included within the frac spread, however these costs are
included in the business line operating margin.
 
 Empress
East gross operating margin was $32.5 million in the fourth quarter of 2009
compared to $0.9 million in the same quarter of 2008.  This $31.6
million increase was primarily due to significantly higher per unit margins,
partially offset by lower propane-plus sales volumes.  Increased per
unit margins were predominantly a result of much higher frac spreads relative to
the prior year.  In addition, during 2008, the unit cost of product
available for sale was much higher, reflecting inventories that were primarily
built up in the second and third quarters when the natural gas price averaged
$8.81 per gj.  These factors were partially offset by an increase in
the extraction premiums paid to purchase natural gas in the fourth quarter of
2009.  Over the past several months, extraction premiums at Empress
have more than doubled as a result of lower eastern gate gas flows through the
Empress facilities.  Eastern gate gas supply in the fourth quarter of
2009 was impacted by lower natural gas drilling activity in western Canada
throughout the year, shut-in natural gas production, and narrower natural gas
pricing differentials between AECO and Chicago.
 
 Fourth
quarter 2009 propane-plus sales volumes were 22 percent lower than in the fourth
quarter of 2008 primarily as a result of lower term sales for
propane-plus.  Empress East term sales arrangements are typically
entered into for the NGL contract year which runs from April 1 to March 31 of
the following year.  During 2009, due to the expiry of Provident’s
lease for fractionation capacity at Sarnia on the first of April, it was
expected that Empress East propane-plus processing capacity for the NGL contract
year would be reduced by 6,000 bpd and term sales commitments were therefore
reduced accordingly.  In August 2009, Provident was successful in
replacing the 6,000 bpd of expired leased fractionation capacity by purchasing
approximately 7,400 bpd of additional fractionation capacity at
Sarnia.  The benefits of this incremental capacity are expected to be
realized in the coming months, particularly as new sales arrangements are
negotiated for the upcoming NGL contract year.  Full realization of
the benefits from this incremental capacity at Sarnia could be impacted by the
availability and the cost of future supply at Empress.
 
 The
Redwater West business line:
 
 The
Redwater West business line purchases an NGL mix from various natural gas
producers and fractionates it into finished products at the Redwater
fractionation facility near Edmonton, Alberta.  Because the feedstock
for this business line is primarily NGL mix rather than natural gas, the frac
spread has a smaller impact on margin than in the Empress East business
line.The Redwater
facility also has the largest and industry-leading rail-based condensate
terminal in western Canada, which serves the heavy oil industry and its need for
diluent.  Year over year, Provident has considerably increased its
condensate market presence at Redwater through marketing, third-party
terminalling and, most recently, storage.  During the third quarter of
2009, two 500,000 barrel storage caverns were
 
 
 
  
 placed
into condensate service at Redwater.  Income generated from the
condensate terminal and caverns which relates to third-party terminalling and
storage is included within the Commercial Services business line.
 
 In the
fourth quarter of 2009, the operating margin for Redwater West was $45.5 million
(2008 - $4.1 million) an increase of $41.4 million.  The significant
increase in margin was primarily due to a significant increase in propane-plus
unit margins.  Over the past several months propane-plus selling
prices have steadily increased resulting in lower priced inventories being sold
into higher priced markets.  In contrast, during the last quarter of
2008, propane-plus prices fell sharply resulting in higher priced inventory
being sold into a significantly lower priced market.  Redwater West
propane-plus selling prices in the fourth quarter of 2009 increased by 14
percent relative to the prior year reflecting higher market prices for
NGL.  Cost of goods sold, on a per unit basis, was three percent lower
than the fourth quarter of 2008 reflecting the higher carrying values of
propane-plus inventories relative to sales prices in the prior
year.
 
 The
increase in propane-plus unit margins was partially offset by an eight percent
reduction in Redwater West propane-plus sales volumes.  Propane-plus
volumes in the fourth quarter of 2009 were lower than the fourth quarter of 2008
as a result of lower NGL product supply.  In the fourth quarter of
2009, Redwater West was most impacted by declining natural gas production in
northwest Alberta and northeastern British Columbia.
 
 The
Commercial Services business line:
 
 The
Commercial Services business line generates income from fee-for-service
contracts to provide fractionation, storage, LPG terminalling, loading and
offloading services.  Income from pipeline tariffs from Provident’s
ownership in NGL pipelines is also included in this business line. In the fourth
quarter of 2009, the margin for this business line increased by 54 percent to
$18.6 million compared to the same period in 2008.  The increased
margin was mostly due to increased fee based revenues associated with the
condensate terminalling facility and incremental storage revenues from the
Provident’s recently completed condensate storage caverns.
 
 Operations
– Midstream NGL sales volumes
 
 Midstream
sold 111,912 bpd in the fourth quarter of 2009, down seven percent when compared
with 120,222 bpd in the fourth quarter of 2008.  The reduction in
volumes primarily represents the decrease in propane-plus volumes in both
Empress East and Redwater West.
 
 Earnings before interest, taxes,
depletion, depreciation, accretion, and other non-cash items (“adjusted
EBITDA”) and funds flow
from operations
 
 Fourth
quarter 2009 adjusted EBITDA increased 62 percent to $60.9 million from $37.7
million in the fourth quarter 2008 reflecting higher operating margins for all
three business lines, partially offset by a higher realized loss on financial
derivative instruments.  The $28.2 million realized loss on financial
derivative instruments was driven by natural gas derivative purchase contracts
that settled at current market prices that were lower than the original
derivative contract prices.  The comparable quarter in 2008 had a
realized gain on financial derivative instruments of $16.1 million, driven
primarily by NGL derivative sales contracts that settled at derivative contract
prices that were higher than the market prices during the settlement
period.  The 2008 adjusted EBITDA amount also included gains on
corporate foreign exchange contracts settled in the period, of which $16.2
million was allocated to the Midstream segment and was included in foreign
exchange (loss) gain and other.  Cash general and administrative
expenses were lower in 2009 as a result of staff reductions and cost cutting
measures implemented within the organization.  Funds flow from
operations for the fourth quarter of 2009 was $55.4 million, an increase of
$20.8 million or 60 percent compared to $34.6 million in the fourth quarter of
2008.  The increase in funds flow from operations reflected the higher
adjusted EBITDA and lower interest expense.
 
 
 
 
 Capital
expenditures
 
 Midstream
capital expenditures for the fourth quarter of 2009 totaled $5.2
million.  In the fourth quarter 2009, $3.7 million was spent primarily
on the continued development of cavern storage and the condensate terminalling
and storage facility.  In addition, $1.3 million was spent on
sustaining capital requirements, and $0.2 million was spent on office related
capital.
      
 
 
 
 2009 Year end
results
  Funds
flow from continuing operations and cash distributions
  Year
      ended December 31,($
      000s, except per unit data)
                  
                  2009
                  
                  
                  2008
                  
                  
                  %
      ChangeFunds
      flow from continuing operations and DistributionsFunds
      flow from continuing operations
                  
                  $
                  264,006
                  
                  
                  $
                  517,622
                  
                  
                  
                  (49
                  )Per
      weighted average unit from continuing operations-
      basic and diluted(1)
                  
                  $
                  1.01
                  
                  
                  $
                  2.03
                  
                  
                  
                  (50
                  )Declared
      distributions
                  
                  $
                  196,217
                  
                  
                  $
                  352,291
                  
                  
                  
                  (44
                  )Per
      unit
                  
                  $
                  0.75
                  
                  
                  $
                  1.38
                  
                  
                  
                  (46
                  )Percent
      of funds flow from continuing
                    operations
      paid out as declared distributions
                  
                  
                  74
                  %
                  
                  
                  68
                  %
                  
                  
                  9(1)Includes dilutive impact of unit options and convertible
      debentures.
 
 For the
year ended December 31, 2009, funds flow from continuing operations decreased
$253.6 million or 49 percent to $264.0 million from $517.6 million for
2008.  On a per unit basis, funds flow from continuing operations
decreased 50 percent in 2009 to $1.01 per unit from $2.03 per unit in
2008.
 
 Provident
Upstream contributed funds flow from operations of $102.2 million in 2009, a
decrease of 70 percent when compared with $338.7 million from
2008.  The decrease was predominantly due to significantly lower
realized crude oil, natural gas liquids and natural gas prices combined with
strategic asset dispositions resulting in lower volumes produced.
 
 Provident
Midstream added $161.8million to
2009 funds flow from operations, compared with $179.0 million recorded in the
year ended December 31, 2008.   Midstream funds flow from
operations reflects a decrease in adjusted EBITDA of $30.4million or
14percent. This
decrease was driven by lower Empress East and Redwater West propane-plus sales
volumes combined with lower Empress East propane-plus unit margins, reflective
of the weaker pricing environment in the earlier part of 2009 compared to a very
strong price environment in the earlier part of 2008.  Reduced cash
interest charges due to lower debt levels partially offset the reduction in
adjusted EBITDA.
 
 Declared
distributions in 2009 totaled $196.2 million, 74 percent of funds flow from
continuing operations.  This compares to $352.3 million of declared
distributions in 2008, 68 percent of funds flow from continuing
operations.  In previous years, Provident has paid out between 67
percent and 102 percent of its annual funds flow from continuing operations as
distributions to unitholders.
 
 Outlook
  The
following outlook contains forward-looking information regarding possible
events, conditions or results of operations in respect of the Trust that is
based on assumptions about future economic conditions and courses of
action.  There are a number of risks and uncertainties which could
cause actual events or results to differ materially from those anticipated by
the Trust and described in the forward-looking information.  See
“Forward-looking information” in this MD&A for additional information
regarding assumptions and risks in respect of the Trust’s forward-looking
information.
 
 Provident
actively monitors commodity prices and overall market conditions on an ongoing
basis and will continue to utilize available cash flow and manage capital
resources to achieve a prudent balance between capital expenditures,
distributions and long term debt.
 
 Provident
Midstream has a capital budget of approximately $86 million for 2010, an
increase of 135 percent compared to the 2009 capital program.  The
Trust plans to allocate approximately $17 million of this budget towards the
expansion and construction of rail and truck terminalling infrastructure at the
Corunna storage facility near
 
 
 
 Sarnia,
upon completion of the acquisition.  Provident anticipates that these
upgrades will enhance operating flexibility and commercial opportunities at
Sarnia.  At Redwater, Provident will direct approximately $15 million
towards advancing a 500,000 barrel condensate cavern that will be commissioned
in early 2011, begin work on a second cavern of equal size slated for completion
in 2012 and construct a brine pond to facilitate future cavern
operations.  Also at Redwater, approximately $18 million will be
allocated to a debottlenecking initiative to increase overall propane-plus
fractionation capacity by 8,000 bpd.  Provident also plans to
undertake a $4 million flare stack recovery initiative to capture and consume
certain byproduct gases, increasing efficiency and reducing
emissions.  Provident also plans to direct approximately $3 million to
construct a 12-truck offloading facility to add an additional option for
receiving NGL supply at the Provident Empress Plant.  The remainder of
the Midstream 2010 capital budget will be used for additional expansion
opportunities, facility optimization initiatives and normal course facility
maintenance at Redwater, Empress and Sarnia.
 
 Key
drivers influencing the Midstream business include access to and cost of NGL mix
and natural gas feedstock, power and fuel costs, and the demand for finished
products including ethane, propane, butane and condensate.  In 2010,
as available propane-plus supply tightens relative to demand, pricing
differentials in Eastern markets where Provident sells the majority of its
Empress East production, may increase relative to other major propane hubs
including Mont Belvieu and Conway.
 
 Provident’s
Upstream Business unit has a capital budget for 2010 of $52 million and plans to
drill, recomplete or workover approximately 53 net oil and natural gas
wells.  Key initiatives in 2010 include approximately $6 million
allocated towards the continuing development of the prospective Pekisko oil
opportunity in Northwest Alberta where Provident is utilizing horizontal wells
and multi-stage fracs.  In 2010, the Trust is drilling two gross
Pekisko wells with the participation of a 50 percent joint venture partner, as
well as optimizing Provident’s existing Pekisko wells.  Additionally,
approximately $12 million will be directed towards the drilling, workover and
recompletion of up to 27 net wells targeting oil and natural gas in the
Northwest Alberta core area.  Provident plans to allocate $16 million
to the Peace River Arch / Dixonville core area, with approximately $7 million
directed towards implementing the second phase of the water flood for enhanced
recovery of Montney “C” crude oil at Dixonville, where Provident will drill two
net wells, convert an existing well to a water injector and install four liners.
Incremental production is expected to be added gradually as the reservoir
responds to the water flood over the next 18 months.  Provident will
also drill an additional three net oil wells in the Peace River Arch
area.  Approximately $17 million of the capital budget will be
directed toward drilling and optimization activities in the Southern Alberta
core area where Provident plans to participate in the drilling, workover or
recompletion of approximately 17 net oil and natural gas wells.  The
reminder of the 2010 capital budget will be allocated to other minor
initiatives.
 
 Oil and
natural gas production in 2010 is expected to average between 9,500 and 10,500
boed and will be weighted approximately 65 percent natural gas and 35 percent
crude oil and liquids.  The third-party pipeline operator has
indicated to Provident that the previously announced pipeline disruption in
Northwest Alberta should be resolved prior to the end of the first
quarter.  Intermittent volume curtailments are expected while the
operator completes the remaining remediation work on the pipeline.
 
 
  
 
 
 Distributions
  The
following table summarizes distributions paid as declared by the Trust since
inception:
  Distribution
      AmountRecord
      Date
                  Payment
      Date
                  
                  (Cdn$)
                  
                  
                  (US$)*2009January
      23, 2009
                  February
      13, 2009
                  
                  $
                  0.09
                  
                  
                  
                  0.07February
      23, 2009
                  March
      13, 2009
                  
                  
                  0.06
                  
                  
                  
                  0.05March
      24, 2009
                  April
      15, 2009
                  
                  
                  0.06
                  
                  
                  
                  0.05April
      22, 2009
                  May
      15, 2009
                  
                  
                  0.06
                  
                  
                  
                  0.05May
      21, 2009
                  June
      15, 2009
                  
                  
                  0.06
                  
                  
                  
                  0.05June
      22, 2009
                  July
      15, 2009
                  
                  
                  0.06
                  
                  
                  
                  0.05July
      22, 2009
                  August
      14, 2009
                  
                  
                  0.06
                  
                  
                  
                  0.05August
      24, 2009
                  September
      15, 2009
                  
                  
                  0.06
                  
                  
                  
                  0.06September
      22, 2009
                  October
      15, 2009
                  
                  
                  0.06
                  
                  
                  
                  0.06October
      22, 2009
                  November
      13, 2009
                  
                  
                  0.06
                  
                  
                  
                  0.06November
      24, 2009
                  December
      15, 2009
                  
                  
                  0.06
                  
                  
                  
                  0.06December
      22, 2009
                  January
      15, 2010
                  
                  
                  0.06
                  
                  
                  
                  0.062009
      Cash Distributions paid as declared
                  
                  
                  $
                  0.75
                  
                  
                  
                  0.672008
      Cash Distributions paid as declared
                  
                  
                  
                  1.38
                  
                  
                  
                  1.292007
      Cash Distributions paid as declared
                  
                  
                  
                  1.44
                  
                  
                  
                  1.352006
      Cash Distributions paid as declared
                  
                  
                  
                  1.44
                  
                  
                  
                  1.262005
      Cash Distributions paid as declared
                  
                  
                  
                  1.44
                  
                  
                  
                  1.202004
      Cash Distributions paid as declared
                  
                  
                  
                  1.44
                  
                  
                  
                  1.102003
      Cash Distributions paid as declared
                  
                  
                  
                  2.06
                  
                  
                  
                  1.472002
      Cash Distributions paid as declared
                  
                  
                  
                  2.03
                  
                  
                  
                  1.292001
      Cash Distributions paid as declared
                    –
      March 2001 – December 2001
                  
                  
                  2.54
                  
                  
                  
                  1.64Inception
      to December 31, 2009 – Distributions paid as declared
                  
                  
                  $
                  14.52
                  
                  
                  
                  11.27*
      Exchange rate based on the Bank of Canada noon rate on the payment
      date.
  For
Canadian tax purposes, both 2009 and 2008 distributions were determined to be
100 percent taxable with no tax deferred return of capital in the hands of
Canadian unitholders.  Distributions received by U.S. resident
unitholders in 2009 and 2008 were considered to be 100 percent qualified
dividends with no tax deferred return of capital.  In both Canada and
the U.S., any tax-deferred portion would usually be treated as an adjustment to
the cost base of the units.  Unitholders or potential unitholders
should consult their own legal or tax advisors as to their particular income tax
consequences of holding Provident units.
 
 Net
(loss) income
  Consolidated
                  Year
      ended December 31,($
      000s, except per unit data)
                  
                  2009
                  
                  
                  2008
                  
                  
                  %
      ChangeNet
      (loss) income
                  
                  $
                  (89,020
                  )
                  
                  $
                  157,392
                  
                  
                  
                  -Per
      weighted average unit–
      basic (1)and diluted(2)
                  
                  $
                  (0.34
                  )
                  
                  $
                  0.62
                  
                  
                  
                  -(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 and
      convertibledebentures.  
   Consolidated
                    Year
      ended December 31,($
      000s)
                    
                    
                    2009
                    
                    
                    
                    2008
                    
                    
                    %
      ChangeProvident
      Upstream net loss
                    
                    $
                    (110,567
                    )
                    
                    $
                    (306,050
                    )
                    
                    
                    (64
                    )Provident
      Midstream net income
                    
                    
                    21,547
                    
                    
                    
                    317,418
                    
                    
                    
                    (93
                    )Net
      (loss) income from continuing operations
                    
                    $
                    (89,020
                    )
                    
                    $
                    11,368
                    
                    
                    
                    -Net
      income from discontinued operations (USOGP)
                    
                    
                    -
                    
                    
                    
                    146,024
                    
                    
                    
                    (100
                    )Consolidated
      net (loss) income
                    
                    $
                    (89,020
                    )
                    
                    $
                    157,392
                    
                    
                    
                    -
  The
Provident Upstream business segment’s net loss in 2009 was $110.6 million, a
$195.5 million improvement compared with year ended December 31, 2008 net loss
of $306.0 million.  The 2008 results included a $416.9 million
non-cash goodwill impairment charge.  Also contributing to the year
over year change was the $244.5 million decrease in adjusted EBITDA, driven by a
significantly lower price environment in 2009 and lower volumes as a result of
strategic asset dispositions.
 
 The
Provident Midstream segment recorded net income of $21.5 million as compared to
net income of $317.4 million in the year ended December 31, 2008.  In
2009, Provident Midstream reported a $30.4 million, or a 14 percent decrease in
adjusted EBITDA compared to 2008.  Further contributing to the
decrease in net income was a change in unrealized (loss) gain on financial
derivative instruments from a gain in 2008 of $191.2 million to a loss in 2009
of $111.6 million.  Under Canadian generally accepted accounting
principles (Canadian GAAP), there is a requirement to “mark-to-market” all
financial derivative instruments at a point in time and report these unrealized
gains or losses as part of current period income.  Because Provident’s
commodity price risk management program involves the use of financial derivative
instruments with terms that currently extend over three years into the future in
the Midstream segment, net earnings can show substantial variation that is not
necessarily related to current operations.  These factors were
partially offset by future income tax recoveries in 2009 of $35.4 million
compared to future income tax expense in 2008 of $20.6 million along with lower
interest expense due to reduced interest rates and debt levels.
 
 Net
income from discontinued operations (USOGP) in 2008 was $146.0
million.  The operations were sold in 2008.
 
 Reconciliation
of non-GAAP measures
  The Trust
calculates earnings before interest, taxes, depletion, depreciation, accretion
and other non-cash items (adjusted EBITDA) within its segment disclosure.
Adjusted EBITDA is a non-GAAP measure.  A reconciliation between
adjusted EBITDA and loss from continuing operations before taxes
follows:
  Year
      ended December 31,($
      000s)
                  
                  2009
                  
                  
                  2008
                  
                  
                  %
      ChangeLoss
      from continuing operations before taxes
                  
                  $
                  (193,564
                  )
                  
                  $
                  (19,817
                  )
                  
                  
                  877Adjusted
      for:Cash
      interest
                  
                  
                  26,989
                  
                  
                  
                  50,793
                  
                  
                  
                  (47
                  )Unrealized
      loss (gain) on financial derivative instruments
                  
                  
                  129,861
                  
                  
                  
                  (221,468
                  )
                  
                  
                  -Goodwill
      impairment
                  
                  
                  -
                  
                  
                  
                  416,890
                  
                  
                  
                  -Depletion,
      depreciation and accretion and other non-cash expenses
                  
                  
                  328,024
                  
                  
                  
                  339,856
                  
                  
                  
                  (3
                  )Adjusted
      EBITDA
                  
                  $
                  291,310
                  
                  
                  $
                  566,254
                  
                  
                  
                  (49
                  )
 
 
 
 
 
  The
following table reconciles funds flow from continuing operations with cash
provided by operating activities:
  Reconciliation
      of funds flow from continuing operations
                  Year
      ended December 31,($
      000s)
                  
                  2009
                  
                  
                  2008
                  
                  
                  %
      ChangeCash
      provided by operating activities
                  
                  $
                  304,248
                  
                  
                  $
                  674,426
                  
                  
                  
                  (55
                  )Change
      in non-cash operating working capital from
                    continuing
      operations
                  
                  
                  (45,641
                  )
                  
                  
                  (52,684
                  )
                  
                  
                  (13
                  )Site
      restoration expenditures
                  
                  
                  5,399
                  
                  
                  
                  6,381
                  
                  
                  
                  (15
                  )Cash
      provided by operating activities from discontinued
    operations
                  
                  
                  -
                  
                  
                  
                  (110,501
                  )
                  
                  
                  -Funds
      flow from continuing operations
                  
                  
                  264,006
                  
                  
                  
                  517,622
                  
                  
                  
                  (49
                  )
   Taxes
  Year
      ended December 31,($
      000s)
                  
                  2009
                  
                  
                  2008
                  
                  
                  %
      ChangeCapital
      tax expense
                  
                  $
                  2,313
                  
                  
                  $
                  3,109
                  
                  
                  
                  (26
                  )Current
      tax expense (recovery)
                  
                  
                  237
                  
                  
                  
                  (4,529
                  )
                  
                  
                  -Future
      income tax recovery
                  
                  
                  (107,094
                  )
                  
                  
                  (29,765
                  )
                  
                  
                  260$
                  (104,544
                  )
                  
                  $
                  (31,185
                  )
                  
                  
                  235
 
 Capital
taxes in 2009 totaled $2.3 million, a decrease from the $3.1 million expense
recorded in 2008.  The decrease reflects the sale of Southeast
Saskatchewan, Southwest Saskatchewan and Lloydminster operating areas in the
latter half of 2009, which were the drivers behind the capital tax
expense.
 
 The
current tax expense of $0.2 million in 2009 compared to a recovery of $4.5
million in 2008.  The 2009 expense was driven by earnings in
Provident’s Canadian Midstream business in excess of allowed tax pool
claims.  The recoveries in 2008 were driven by lower earnings subject
to tax in the U.S. Midstream operations allowing the recovery of taxes paid in
prior periods.
 
 For the
year ended December 31, 2009, the future income tax recovery was $107.1 million,
compared with a recovery of $29.8 million in 2008.  In both 2009 and
2008, future income tax recoveries were recorded as a result of losses created
by interest and royalty deductions at the incorporated subsidiary
level.  However in 2009, further adding to recoveries were unrealized
losses on financial derivative instruments compared to future tax expense in
2008 relating to the unrealized gains on financial derivative
instruments.  In 2008, additional future income tax recoveries were
recorded as a result of an internal structural reorganization.  The
goodwill impairment charge in 2008 had no impact on future income
taxes.
 
 The Trust
has estimated its future income taxes based on estimates of results of
operations and tax pool claims and cash distributions in the
future.  The Trust’s estimate of its future income taxes will vary as
these underlying estimates change and such variations may be
material.
 
 In June
2007, the Department of Finance (Canada) enacted legislation, effective for
2011,  respecting the taxation of certain “specified investment
flow-through” (“SIFT”) trusts, including Provident, and SIFT partnerships (the
“SIFT Tax”).  Subsequent to 2010, to the extent the Trust receives
taxable income the SIFT Tax would be payable by the Trust prior to paying its
distributions. These distributions would generally be considered taxable
dividends to unitholders with Canadian unitholders able to claim the dividend
tax credit for units held in taxable accounts effectively lowering the personal
tax rate on distributions received. Canadian investors who hold Trust units in a
tax deferred account will not be able to claim the dividend tax
credit.   Distributions that are determined to be a return of
capital would not be subject to the SIFT tax at the Trust and would continue to
reduce the Canadian unitholders adjusted cost base.  Distributions to
U.S. residents after 2010 will be subject to Canadian withholding tax,
consistent
 
 
 with the
current treatment of Trust distributions while the current classification as
qualified dividends or return of capital will be dependent on U.S. tax
legislation.
 
 In March
2009, legislation was enacted that amended the Income Tax Act including
technical amendments to clarify certain aspects of the SIFT Tax and to provide
rules to facilitate the conversion of existing SIFT trusts into corporations on
a tax-deferred basis.  A corporate conversion would be achieved
through a Plan of Arrangement which must be approved by the Trust’s Board of
Directors and voted on by unitholders at a special
meeting.  Subsequent to a conversion to a corporation, Canadian
shareholders would receive taxable dividends eligible for the dividend tax
credit. The tax impact of the dividends may be different for shareholders
depending on their jurisdiction and whether they are holding their investment in
a taxable account or tax-deferred account.  Dividends received by U.S.
residents after 2010 could be treated as qualified dividends or return of
capital, depending on U.S. tax legislation, while the Canadian withholding tax
will be consistent with the current treatment for trust
distributions.  The Board of Directors and management continue to
evaluate options, including a possible conversion to a corporation, to best
position Provident beyond 2010 when the Trust will become subject to SIFT
Tax.
 
 At
December 31, 2009 the Trust has approximately $1.2 billion of intangible,
tangible and non-capital loss tax pools available to claim against taxable
income under either a trust or corporate structure.
 
 Interest
expense
 
 Continuing
      operations
                  
                  Year
      ended December 31,($
      000s, except as noted)
                  
                  2009
                  
                  
                  2008
                  
                  
                  %
      ChangeInterest
      on bank debt
                  
                  $
                  9,634
                  
                  
                  $
                  35,044
                  
                  
                  
                  (73
                  )Interest
      on convertible debentures
                  
                  
                  17,355
                  
                  
                  
                  19,934
                  
                  
                  
                  (13
                  )Discontinued
      operations portion
                  
                  
                  -
                  
                  
                  
                  (4,185
                  )
                  
                  
                  (100
                  )Total
      cash interest
                  
                  $
                  26,989
                  
                  
                  $
                  50,793
                  
                  
                  
                  (47
                  )Weighted
      average interest rate on all long-term debt
                  
                  
                  3.6
                  %
                  
                  
                  5.3
                  %
                  
                  
                  (32
                  )Debenture
      accretion and other non-cash interest expense
                  
                  
                  4,828
                  
                  
                  
                  5,239
                  
                  
                  
                  (8
                  )Total
      interest expense
                  
                  $
                  31,817
                  
                  
                  $
                  56,032
                  
                  
                  
                  (43
                  )
 
 Interest
expense decreased in 2009 compared to 2008 due to lower debt levels and lower
market interest rates. Cash proceeds from 2009 Upstream dispositions totaling
$305.7 million as well as the sale of USOGP in 2008, amounting to $457.9
million, net of tax, were used to pay down debt.
 
 Financial
instruments
 
 Commodity
price risk management program
 
 Provident’s
commodity price risk management program utilizes derivative instruments to
provide protection against lower commodity prices and margins.  The
program reduces exposure to downside commodity price volatility and provides
support for cash distributions, bank lending capacity, capital programs and
acquisition and project economics.  The program 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.  For the Midstream business unit the
program provides price stabilization and protection of a percentage of inventory
values and fractionation spread margin.  The Program also reduces
foreign exchange risk due to the exposure arising from the conversion of U.S.
dollars into Canadian dollars, interest rate risk and fixes a portion of
Provident’s input costs.
 
 The
commodity price derivative instruments the Trust uses include put and call
options, costless collars, participating swaps, and fixed price products that
settle against indexed referenced pricing.
  
 
 Provident’s
credit policy governs the activities undertaken to mitigate non-performance risk
by counterparties to financial derivative instruments.  Activities
undertaken include regular monitoring of counterparty exposure to approved
credit limits, financial reviews of all active counterparties, utilizing
International Swap Dealers Association (ISDA) agreements and obtaining financial
assurances where warranted.  In addition, Provident has a diversified
base of available counterparties.
 
 In the
Midstream business, production margins are affected by the spread between the
purchase cost of natural gas and sales price of propane, butane and
condensate.  Market conditions have not provided sufficient or
adequate opportunity to directly manage 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, crude oil and foreign
exchange financial derivative contracts through March 2013 in order to protect
operating margins in the Midstream business.  Short term financial
derivative instruments directly fixing propane, butane, natural gasoline and
electricity prices have also been executed.
 
 Settlement
of financial derivative contracts
  The
following table summarizes the impact of the financial derivative contracts
settled during the years ended December 31, 2009 and 2008, included in realized
loss on financial derivative instruments.
  Realized
      gain (loss) on financial derivative instruments
                  
                  2009
                  
                  
                  2008($
      000s except volumes)
                  
                  
                  
                  
                  Volume(1)
                  
                  
                  
                  
                  
                  Volume(1)Provident
      UpstreamCrude
      Oil
                  
                  $
                  8,052
                  
                  
                  
                  0.8
                  
                  
                  $
                  (11,113
                  )
                  
                  
                  1.6Natural
      gas
                  
                  
                  8,336
                  
                  
                  
                  6.1
                  
                  
                  
                  11
                  
                  
                  
                  10.9Provident
      MidstreamCrude
      Oil
                  
                  
                  29,007
                  
                  
                  
                  4.1
                  
                  
                  
                  (135,602
                  )
                  
                  
                  4.2Natural
      gas
                  
                  
                  (95,188
                  )
                  
                  
                  23.0
                  
                  
                  
                  (16,978
                  )
                  
                  
                  26.8NGL's
      (includes propane, butane)
                  
                  
                  5,072
                  
                  
                  
                  0.8
                  
                  
                  
                  25,902
                  
                  
                  
                  2.3Foreign
      Exchange
                  
                  
                  (3,505
                  )
                  
                  
                  -
                  
                  
                  
                  5,387
                  
                  
                  
                  -Electricity
                  
                  
                  (1,276
                  )
                  
                  
                  -
                  
                  
                  
                  2,374
                  
                  
                  
                  -CorporateInterest
      Rate (2)
                  
                  
                  (1,137
                  )
                  
                  
                  -
                  
                  
                  
                  -
                  
                  
                  
                  -Realized
      loss on financial derivative instruments
                  
                  $
                  (50,639
                  )
                  
                  
                  
                  
                  
                  $
                  (130,019
                  )
                  
                  
                  -(1)
      The above table represents aggregate net volumes that were bought/sold
      over the periods. Crude oil and NGL volumes are listed
      inmillions
      of barrels and natural gas is listed in millions of
      gigajoules.(2)
      Realized gains and losses on corporate related interest rate contracts are
      allocated to the reporting segments for segmented
      reportingpurposes.
  
 The
realized loss for the year ended December 31, 2009 was $50.6 million compared to
a realized loss of $130.0 million in 2008.  The realized loss in 2009
was driven by natural gas purchase derivative contracts in the midstream
business settling at a contracted price higher than the current market natural
gas prices, partially offset by crude oil derivative sales contracts in both
business units settling at contracted crude oil prices higher than the crude oil
market prices during the settlement period.  The comparable 2008
realized loss was driven mostly by crude oil derivative sales contracts in the
midstream business settling at contracted crude oil prices lower than the crude
oil market prices during the settlement period.
  In
addition, the Trust recorded a loss of $0.2 million (2008 - $26.8 million gain)
on corporate foreign exchange contracts.  The amounts were included in
foreign exchange loss (gain) and other on the consolidated statement of
operations and were allocated to the reporting segments.
  
 
 The
following table is a summary of the net financial derivative instruments
liability:
  As
      at December 31,($
      000s)
                  
                  2009
                  
                  
                  2008Provident
      UpstreamCrude
      Oil
                  
                  $
                  826
                  
                  
                  $
                  (12,521
                  )Natural
      Gas
                  
                  
                  1,545
                  
                  
                  
                  (3,285
                  )Provident
      Midstream
                  
                  
                  181,890
                  
                  
                  
                  70,476Corporate
                  
                  
                  269
                  
                  
                  
                  -Total
                  
                  $
                  184,530
                  
                  
                  $
                  54,670
  The net
liability in both periods represents unrealized “mark-to-market” opportunity
costs related to financial derivative instruments with contract settlements
ranging from January 1, 2010 through March 31, 2013.  The balances are
required to be recognized in the financial statements under generally accepted
accounting principles.  These financial derivative instruments were
entered into in order to manage commodity prices and protect future Midstream
product margins.  Fluctuations in the market value of these
instruments impact earnings prior to their settlement dates but have no impact
on funds flow from operations until the instrument is actually
settled.
 
 Goodwill
and intangible assets
 
 Goodwill
represents the excess of the cost of an acquired enterprise over the net of the
amounts assigned to assets acquired and liabilities assumed.  As at
December 31, 2009 and 2008, the goodwill balance of $100.4 million was related
entirely to the Provident Midstream reporting unit.
 
 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.  The impairment test includes a comparison of the net book
value of the Trust’s assets, by reporting units, to the estimated fair value of
the reporting unit.  In 2009, Provident engaged the services of a
third-party evaluator to assist in determining fair value.  Valuation
methodologies included discounted cash flow, a transaction-based approach and a
market-based approach, using trading multiples.  Goodwill is not
amortized.
 
 The Trust
performed its annual goodwill impairment test in the fourth quarter of 2009 and
determined that no write-down of goodwill was required. In 2008, a goodwill
impairment of $416.9 million was recorded in the upstream business
unit.
 
 Provident’s
intangible assets primarily relate to Midstream contracts and customer
relationships.  In 2009, the Trust recognized an impairment of $12.4
million on a specific Midstream marketing agreement. The Trust had been
amortizing the agreement over a 15 year period.  The Trust now expects
that it is unlikely that the agreement will be renewed beyond March 31, 2011 on
the same terms.  In addition, during 2009, the volumes supplied to the
Trust under this agreement were reduced as a result of certain property
dispositions completed by the third party supplier.  The impairment
reflects a revision of the amortization period of this agreement and lower
volume expectations for the remainder of the contract.  The impairment
was recognized in the statement of operations in depletion, depreciation, and
accretion expense.  The Trust does not expect the change in this
contract to have a significant impact on volumes purchased in the Midstream
business.
 
 
 
 
 Liquidity
and capital resources
  Consolidated($
      000s)
                  
                  December
      31, 2009
                  
                  
                  December
      31, 2008
                  
                  
                  %
      ChangeLong-term
      debt - revolving term credit facility
                  
                  $
                  264,776
                  
                  
                  $
                  504,685
                  
                  
                  
                  (48
                  )Long-term
      debt - convertible debentures (including current portion)
                  
                  
                  240,486
                  
                  
                  
                  260,994
                  
                  
                  
                  (8
                  )Working
      capital surplus (excluding financial derivative
    instruments)
                  
                  
                  (31,152
                  )
                  
                  
                  (39,041
                  )
                  
                  
                  (20
                  )Net
      debt
                  
                  $
                  474,110
                  
                  
                  $
                  726,638
                  
                  
                  
                  (35
                  )Unitholders'
      equity (at book value)
                  
                  
                  1,381,399
                  
                  
                  
                  1,636,347
                  
                  
                  
                  (16
                  )Total
      capitalization at book value
                  
                  $
                  1,855,509
                  
                  
                  $
                  2,362,985
                  
                  
                  
                  (21
                  )Total
      net debt as a percentage of total book value
capitalization
                  
                  
                  26
                  %
                  
                  
                  31
                  %
                  
                  
                  (16
                  )
  
 Provident
operates two business units with similar but not identical monthly cash
settlement cycles.  Midstream revenues are received at various times
throughout the month.  Provident’s working capital position is
affected by seasonal fluctuations that reflect commodity price changes, drilling
cycles in its oil and gas operations and inventory balances in its Midstream
business unit.  Provident relies on funds flow from continuing
operations, external lines of credit and access to equity markets to fund
capital programs and acquisitions.
 
 As a
result of the weakening of the global economy in 2008, oil and gas industry
participants, including Provident, had been experiencing more restricted access
to capital.  Recent activity in the capital markets towards the end of
2009 has shown signs of improvement, however increased borrowing costs are still
anticipated.  Although Provident’s core businesses have not changed,
risk premiums have increased.  Management believes that cash flows
from operating activities and availability under existing bank facilities will
be adequate to allow Provident to move forward with its budgeted 2010 capital
program.  However, these issues will affect Provident as it reviews
financing alternatives for future capital expenditures and potential acquisition
opportunities.
 
 Substantially
all of Provident'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. Provident partially mitigates associated credit risk
by limiting transactions with certain counterparties to limits imposed by
Provident based on management’s assessment of the creditworthiness of such
counterparties.  In certain circumstances, Provident will require the
counterparties to provide payment prior to delivery, letters of credit and/or
parental guarantees.  The carrying value of accounts receivable
reflects management's assessment of the associated credit risks.
 
 Contractual
obligations
  Consolidated
                  
                  Payment
      due by period($
      millions)
                  
                  Total
                  
                  
                  Less
      than 1 year
                  
                  1
      to 3 years
                  
                  3
      to 5 years
                  
                  
                  More
      than 5 yearsLong-term
      debt - revolving term credit facility (1)
      (2)
                  
                  $
                  270.2
                  
                  
                  $
                  3.7
                  
                  
                  $
                  266.5
                  
                  
                  $
                  -
                  
                  
                  $
                  -Long-term
      debt - convertible debentures(2)
                  
                  
                  279.2
                  
                  
                  
                  16.2
                  
                  
                  
                  263.0
                  
                  
                  
                  -
                  
                  
                  
                  -Operating
      lease obligations
                  
                  
                  164.0
                  
                  
                  
                  18.1
                  
                  
                  
                  30.0
                  
                  
                  
                  21.7
                  
                  
                  
                  94.2Total
                  
                  $
                  713.4
                  
                  
                  $
                  38.0
                  
                  
                  $
                  559.5
                  
                  
                  $
                  21.7
                  
                  
                  $
                  94.2(1)
      The terms of the Canadian credit facility have a revolving three year
      period expiring on May 30, 2011.(2)
      Includes associated interest and principal payments.
   Long-term
debt and working capital
 
 In 2009,
Provident’s Canadian term credit facility was reduced by $95 million to $1.03
billion due to the asset dispositions in the Upstream business
unit.  On March 1, 2010, Provident closed the previously announced
sale of
 
 
 
 West
Central Alberta oil and natural gas assets.  As a result of this sale,
Provident’s Canadian term credit facility was reduced by an additional $50
million to $980 million.
 
 As at
December 31, 2009 Provident had drawn on 26 percent of its term credit facility
as compared to 45 percent drawn as at December 31, 2008.  The decrease
in the level of bank debt was a result of the application of proceeds from the
Upstream strategic property dispositions.
 
 At
December 31, 2009 Provident had letters of credit guaranteeing Provident’s
performance under certain commercial and other contracts that totaled $27.2
million, increasing bank line utilization to 28 percent.  The
guarantees at December 31, 2008 totaled $35.2 million.
 
 The
following table shows the change in Provident’s working capital
position:
  As
      at December 31,($
      000s)
                  
                  2009
                  
                  
                  2008
                  
                  
                  ChangeCurrent
      AssetsCash
      and cash equivalents
                  
                  $
                  7,187
                  
                  
                  $
                  4,629
                  
                  
                  $
                  2,558Accounts
      receivable
                  
                  
                  216,786
                  
                  
                  
                  244,485
                  
                  
                  
                  (27,699
                  )Petroleum
      product inventory
                  
                  
                  37,261
                  
                  
                  
                  46,160
                  
                  
                  
                  (8,899
                  )Prepaid
      expenses and other current assets
                  
                  
                  4,803
                  
                  
                  
                  7,886
                  
                  
                  
                  (3,083
                  )Financial
      derivative instruments
                  
                  
                  5,314
                  
                  
                  
                  16,708
                  
                  
                  
                  (11,394
                  )Current
      LiabilitiesAccounts
      payable and accrued liabilities
                  
                  
                  221,417
                  
                  
                  
                  244,031
                  
                  
                  
                  22,614Cash
      distribution payable
                  
                  
                  13,468
                  
                  
                  
                  20,088
                  
                  
                  
                  6,620Current
      portion of convertible debentures
                  
                  
                  -
                  
                  
                  
                  24,871
                  
                  
                  
                  24,871Financial
      derivative instruments
                  
                  
                  86,441
                  
                  
                  
                  13,693
                  
                  
                  
                  (72,748
                  )Working
      capital (deficit) surplus
                  
                  $
                  (49,975
                  )
                  
                  $
                  17,185
                  
                  
                  $
                  (67,160
                  )
  
 The ratio
of net debt (as calculated under “Liquidity and capital resources”) to funds
flow from continuing operations in 2009 was 1.8 to one, compared to 1.4 to one
in 2008.  The increase reflects a decrease in net debt offset by lower
funds flow from operations.  On a segmented basis, using allocated
debt balances as disclosed in note 20 to the consolidated financial statements,
the Provident Upstream business had a ratio of net debt to funds flow from
operations in 2009 of 1.6 to one (2008 – 0.7 to one).  The ratio for
the Provident Midstream business unit was 2.0 to one in 2009, compared to 2.7 to
one in 2008.
 
 Trust
units
 
 For the
year ended December 31, 2009 the Trust issued no additional units on conversion
of convertible debentures (2008 – six thousand units).  No additional
units were issued pursuant to the expired unit option plan for the year ended
December 31, 2009 (2008 – 0.2 million units).  Under Provident’s
Premium Distribution, Distribution Reinvestment (DRIP) and Optional Unit
Purchase Plan program 5.2 million units were issued or are to be issued in 2009
representing proceeds of $28.1 million (2008 – 6.3 million units for proceeds of
$53.8 million).
 
 At
December 31, 2009 management and directors held less than one percent of the
outstanding trust units.
 
 
 
 
 Capital
related expenditures and funding
  Continuing
      operations
                  
                  Year
      ended December 31,($
      000s)
                  
                  2009
                  
                  
                  2008
                  
                  
                  %
      ChangeCapital
      related expendituresCapital
      expenditures
                  
                  $
                  (127,369
                  )
                  
                  $
                  (246,947
                  )
                  
                  
                  (48
                  )Site
      restoration expenditures
                  
                  
                  (5,399
                  )
                  
                  
                  (6,381
                  )
                  
                  
                  (15
                  )Acquisitions
                  
                  
                  (18,833
                  )
                  
                  
                  (25,843
                  )Net
      capital related expenditures
                  
                  $
                  (151,601
                  )
                  
                  $
                  (279,171
                  )
                  
                  
                  (46
                  )Funded
      byFunds
      flow from continuing operations net of declared
                    distributions
      to unitholders
                  
                  $
                  67,789
                  
                  
                  $
                  165,331
                  
                  
                  
                  (59
                  )Cash
      proceeds on sale of assets
                  
                  
                  305,720
                  
                  
                  
                  1,662Proceeds
      on sale of discontinued operations, net of tax
                  
                  
                  -
                  
                  
                  
                  457,906Decrease
      in long-term debt
                  
                  
                  (265,245
                  )
                  
                  
                  (440,244
                  )
                  
                  
                  (40
                  )Issue
      of trust units, net of cost; excluding DRIP
                  
                  
                  -
                  
                  
                  
                  1,672
                  
                  
                  
                  -DRIP
      proceeds
                  
                  
                  28,106
                  
                  
                  
                  53,838
                  
                  
                  
                  (48
                  )Change
      in working capital, including cash, and change
                    in
      investments
                  
                  
                  15,231
                  
                  
                  
                  39,006
                  
                  
                  
                  (61
                  )Net
      capital related expenditure funding
                  
                  $
                  151,601
                  
                  
                  $
                  279,171
                  
                  
                  
                  (46
                  )
  Provident
has funded its net capital expenditures with cash flow from operations and
long-term debt.  Proceeds on sale of assets were applied to
Provident’s revolving term credit facility.
 
 Strategic
review and restructuring expenses
 
 The
strategic review process was announced in February of 2008 with the objectives
of optimizing business performance, facilitating business growth, improving
overall access to and cost of capital, enhancing the valuation of Provident’s
component businesses and optimizing structure in response to the federal
government decision to tax income trusts beginning in 2011.  During
this review, it was determined that the sale of the United States oil and
natural gas production (USOGP) business was an important step in the
process.  Following the sale of USOGP, management and the board of
directors evaluated the complete spectrum of strategic options available for
Provident’s remaining Canadian oil and gas production (Provident Upstream) and
midstream (Provident Midstream) business units.  After an extensive
review, it was determined that in early 2009, in the context of the
macroeconomic environment (characterized by low commodity prices and volatility
in both equity and debt markets at that time), it was in the best interest of
unitholders that Provident remain structured as a cash-distributing, diversified
energy enterprise.  Provident also completed an internal
reorganization to improve the efficiency and competitiveness of the businesses.
The internal reorganization was designed to improve the focus of each business
unit, improve management’s line of sight to the key performance measures in each
business, and reduce general and administrative costs.
 
 As the
macroeconomic environment evolved throughout 2009, Provident determined it was
appropriate to sell certain non-strategic Upstream producing oil and natural gas
assets.  In the third and fourth quarters of 2009, Provident sold
$322.7 million of Upstream assets and in March of 2010, closed the sale of its
West Central Alberta operating area for $177 million.  The Board of
Directors and management continue to evaluate options that will best position
Provident beyond 2010 when the Trust distributions will become subject to
tax.  The reorganization and 2009 divestitures resulted in staff
reductions at all levels of the organization, including senior
management.  For the year ended December 31, 2009, strategic review
and restructuring costs were $12.3 million (2008 - $3.6 million).  The
costs are comprised primarily of severance, consulting and legal
costs.
 
 
 
 
 Unit
based compensation
 
 Unit
based compensation includes expenses or recoveries associated with Provident’s
restricted and performance unit plan.  Unit based compensation is
recorded at the estimated fair value of the notional units
granted.  Compensation expense associated with the plans is recognized
in earnings over the vesting period of each plan.  The expense or
recovery associated with each period is recorded as non-cash unit based
compensation (a component of general and administrative expense).  A
portion relating to operational employees at field and plant locations is also
allocated to operating expense.  For the year ended December 31, 2009,
Provident recorded unit based compensation expense of $18.4 million (2008 - $4.4
million) and made related cash payments of $11.5 million (2008 - $8.3 million),
of which $3.3 is included in strategic review and restructuring
expense.  The expense was higher in 2009 as a result of a higher
Provident trust unit trading price, upon which the compensation is
based.  At December 31, 2009, the current portion of the liability
totaled $12.2 million (December 31, 2008 - $9.4 million) and the long-term
portion totaled $12.5 million (December 31, 2008 - $8.6 million).
    
 
 
 
 Provident
Upstream segment review
 
 Upstream
asset dispositions
 
 On
September 30, 2009, Provident completed a sale of the operating areas of
Southeast and Southwest Saskatchewan for net proceeds of $225.7 million and a
separate sale of a minor property in the Lloydminster area for $12.8
million.  Production on the date of announcement for these operating
areas totaled approximately 4,000 boed.
 
 On
November 30, 2009, Provident closed the sale of the remaining properties in the
Lloydminster operating area to a private company, Emerge Oil & Gas Inc. for
total consideration of $84.0 million, consisting of $67.0 million in cash and
$17.0 million in equity of the acquirer.  Production on the date of
announcement for these properties totaled approximately 2,200 boed.
 
 Net
proceeds from these dispositions have been applied to Provident’s revolving term
credit facility.
 
 On
December 23, 2009, Provident announced that it had reached an agreement with
Storm Ventures International Inc. to sell the oil and natural gas assets in the
West Central Alberta operating area.  Production on the date of
announcement for these properties totaled approximately 5,000
boed.  The transaction closed on March 1,
2010.   Proceeds from the transaction of $177 million were
applied to Provident’s revolving term credit facility.
 
 Crude
oil and natural gas liquids prices
 
 The
following realized prices are net of transportation expense.
  Provident
      Upstream
                  
                  Year
      ended December 31,($
      per bbl)
                  
                  2009
                  
                  
                  2008
                  
                  
                  %
      ChangeOil
      per barrelWTI
      (US$)
                  
                  $
                  61.80
                  
                  
                  $
                  99.65
                  
                  
                  
                  (38
                  )Exchange
      rate (from US$ to Cdn$)
                  
                  
                  1.14
                  
                  
                  
                  1.07
                  
                  
                  
                  7WTI
      expressed in Cdn$
                  
                  $
                  70.54
                  
                  
                  $
                  106.33
                  
                  
                  
                  (34
                  )Realized
      pricing before financial derivative instrumentsCrude
      oil
                  
                  $
                  54.15
                  
                  
                  $
                  82.79
                  
                  
                  
                  (35
                  )Natural
      gas liquids
                  
                  $
                  44.40
                  
                  
                  $
                  76.88
                  
                  
                  
                  (42
                  )Crude
      oil and natural gas liquids
                  
                  $
                  53.05
                  
                  
                  $
                  82.27
                  
                  
                  
                  (36
                  )
 
 For the
year ended December 31, 2009 Provident’s realized crude oil and natural gas
liquids price, prior to the impact of financial derivative instruments,
decreased by 36 percent to average $53.05 compared to $82.27 in
2008.  The 2009 decrease related to a 38 percent decrease in US$ WTI
crude oil price, partially offset by an increase in U.S. to Canadian dollar
exchange rate.
 
 Natural
gas price
 
 The
following prices are net of transportation expense.
  Provident
      UpstreamYear
      ended December 31,(Cdn$
      per mcf)
                  
                  2009
                  
                  
                  2008
                  
                  
                  %
      ChangeAECO
      monthly index
                  
                  $
                  4.14
                  
                  
                  $
                  8.12
                  
                  
                  
                  (49
                  )Corporate
      natural gas price per mcf before financial
                    derivative
      instruments
                  
                  $
                  3.86
                  
                  
                  $
                  8.23
                  
                  
                  
                  (53
                  )
  
 
 For the
year ended December 31, 2009 Provident’s realized natural gas price, excluding
financial derivative instruments, decreased 53 percent as compared to 2008,
comparable to the decrease in the benchmark AECO monthly index
price.  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
  Year
      ended December 31,Provident
      Upstream
                  
                  2009
                  
                  
                  2008
                  
                  
                  %
      ChangeDaily
      productionCrude
      oil (bpd)
                  
                  
                  8,875
                  
                  
                  
                  12,473
                  
                  
                  
                  (29
                  )Natural
      gas liquids (bpd)
                  
                  
                  1,121
                  
                  
                  
                  1,203
                  
                  
                  
                  (7
                  )Natural
      gas (mcfd)
                  
                  
                  69,575
                  
                  
                  
                  84,039
                  
                  
                  
                  (17
                  )Oil
      equivalent (boed) (1)
                  
                  
                  21,592
                  
                  
                  
                  27,683
                  
                  
                  
                  (22
                  )(1)
      Provident reports equivalent production converting natural gas to oil on a
      6:1 basis.
  For the
year ended December 31, 2009, Provident Upstream production averaged 21,592
boed, a 22 percent decrease compared to 27,683 boed in
2008.  Production levels for 2009 were lower as a result of strategic
upstream asset dispositions.  Production from the properties sold
averaged 4,953 boed in 2009 compared to 8,075 boed in 2008.  Further
contributing to the decrease in daily production were natural declines that were
larger than the production additions from capital expenditures.  The
lower commodity price environment resulted in reduced capital spending compared
to 2008, as well, the nature of the 2009 capital expenditures was focused on
longer term plays.  The majority of the capital spent in 2009 was
spent on Northwest Alberta facilities and pipelines for the emerging Pekisko
resource play and on Dixonville’s waterflood program.  These longer
term plays do not result in immediate production gains but are key to position
Provident Upstream for future growth.
 
 In
Dixonville, 21 crude oil wells were converted to water injectors in 2009 as part
of the phase one expansion. Production from these wells in 2008 was
approximately 500 bpd.  The approval for the phase two expansion was
received in January 2010 and an application for phase three was submitted in
February 2010.  Production growth in Dixonville is expected to
increase as the waterflood matures with incremental production expected
gradually over the next 18 months.
 
 Production
for 2009 was weighted 54 percent natural gas and 46 percent crude oil and
natural gas liquids.  This compared to 2008 production weighted 51
percent natural gas and 49 percent crude oil and natural gas
liquids.  Year end 2009 exit-rate production was approximately 15,200
boed, including approximately 5,100 boed related to the West Central Alberta
operating area which was subsequently sold on March 1, 2010.
 
 Provident
Upstream production summarized by operating areas is as follows:
  Year
      ended December 31,Provident
      Upstream
                  
                  2009
                  
                  
                  2008
                  
                  
                  %
      ChangeDaily
      Production - by area (boed) (1)West
      Central Alberta
                  
                  
                  5,401
                  
                  
                  
                  6,271
                  
                  
                  
                  (14
                  )Southern
      Alberta
                  
                  
                  4,629
                  
                  
                  
                  4,883
                  
                  
                  
                  (5
                  )Northwest
      Alberta
                  
                  
                  3,771
                  
                  
                  
                  4,690
                  
                  
                  
                  (20
                  )Dixonville
                  
                  
                  2,838
                  
                  
                  
                  3,764
                  
                  
                  
                  (25
                  )16,639
                  
                  
                  
                  19,608
                  
                  
                  
                  (15
                  )Other(2)
                  
                  
                  4,953
                  
                  
                  
                  8,075
                  
                  
                  
                  (39
                  )21,592
                  
                  
                  
                  27,683
                  
                  
                  
                  (22
                  )(1)
      Provident reports equivalent production converting natural gas to oil on a
      6:1 basis.(2)Includes
      Southeast Saskatchewan and Southwest Saskatchewan operating areas that
      were sold on September 30, 2009 andLloydminster
      operating area that was sold November 30, 2009.
  
 Revenue
and royalties
 
 Provident
      Upstream
                    
                    Year
      ended December 31,($
      000s except per boe and mcf data)
                    
                    2009
                    
                    
                    2008
                    
                    
                    %ChangeOilRevenue
                    
                    $
                    175,408
                    
                    
                    $
                    377,976
                    
                    
                    
                    (54
                    )Realized
      gain (loss) on financial derivative instruments
                    
                    
                    8,052
                    
                    
                    
                    (11,113
                    )
                    
                    
                    -Royalties
                    
                    
                    (31,468
                    )
                    
                    
                    (69,897
                    )
                    
                    
                    (55
                    )Net
      revenue
                    
                    $
                    151,992
                    
                    
                    $
                    296,966
                    
                    
                    
                    (49
                    )Net
      revenue (per barrel)
                    
                    $
                    46.92
                    
                    
                    $
                    65.05
                    
                    
                    
                    (28
                    )Royalties
      as a percentage of revenue
                    
                    
                    17.9
                    %
                    
                    
                    18.5
                    %Natural
      gasRevenue
                    
                    $
                    98,011
                    
                    
                    $
                    253,183
                    
                    
                    
                    (61
                    )Realized
      gain on financial derivative instruments
                    
                    
                    8,336
                    
                    
                    
                    11
                    
                    
                    
                    75,682Royalties
                    
                    
                    (4,826
                    )
                    
                    
                    (44,715
                    )
                    
                    
                    (89
                    )Net
      revenue
                    
                    $
                    101,521
                    
                    
                    $
                    208,479
                    
                    
                    
                    (51
                    )Net
      revenue (per mcf)
                    
                    $
                    4.00
                    
                    
                    $
                    6.78
                    
                    
                    
                    (41
                    )Royalties
      as a percentage of revenue
                    
                    
                    4.9
                    %
                    
                    
                    17.7
                    %Natural
      gas liquidsRevenue
                    
                    $
                    18,166
                    
                    
                    $
                    33,857
                    
                    
                    
                    (46
                    )Royalties
                    
                    
                    (5,281
                    )
                    
                    
                    (8,528
                    )
                    
                    
                    (38
                    )Net
      revenue
                    
                    $
                    12,885
                    
                    
                    $
                    25,329
                    
                    
                    
                    (49
                    )Net
      revenue (per barrel)
                    
                    $
                    31.49
                    
                    
                    $
                    57.53
                    
                    
                    
                    (45
                    )Royalties
      as a percentage of revenue
                    
                    
                    29.1
                    %
                    
                    
                    25.2
                    %TotalRevenue
                    
                    $
                    291,585
                    
                    
                    $
                    665,016
                    
                    
                    
                    (56
                    )Realized
      gain (loss) on financial derivative instruments
                    
                    
                    16,388
                    
                    
                    
                    (11,102
                    )
                    
                    
                    -Royalties
                    
                    
                    (41,575
                    )
                    
                    
                    (123,140
                    )
                    
                    
                    (66
                    )Net
      revenue
                    
                    $
                    266,398
                    
                    
                    $
                    530,774
                    
                    
                    
                    (50
                    )Net
      revenue (per boe)
                    
                    $
                    33.80
                    
                    
                    $
                    52.39
                    
                    
                    
                    (35
                    )Royalties
      as a percentage of revenue
                    
                    
                    14.3
                    %
                    
                    
                    18.5
                    %Note: the
      above revenue, net revenue and net revenue per boe figures are presented
      net of transportation expenses and the realized gain (loss) on financial
      derivative instruments excludes the impact of corporate interest rate swap
      gains/losses allocated to Provident Upstream.
  For the
year ended December 31, 2009 Provident Upstream production revenue was $291.6
million, a decrease of 56 percent from $665.0 million in 2008.  The
decrease in revenue was a result of a 44 percent decrease in prices per boe due
to lower realized crude oil, natural gas liquids, and natural gas prices as well
as a 22 percent decrease in production.  Royalties, which are price sensitive
and affected by production rates, decreased as a percentage of revenue
mainly due to significantly lower natural gas prices.  Alberta natural
gas crown royalties were also reduced to reflect the impact of prior year
capital expenditures spent on natural gas facilities within the
province.  The preceding factors as well as the $16.4 million realized
gain on financial derivative instruments compared to a $11.1 million realized
loss in 2008, account for net revenue of $266.4 million in 2009, 50 percent
lower than the $530.8 million recorded in 2008.
 
 Net
revenue per boe in 2009 decreased 35 percent to $33.80 from $52.39 in 2008
resulting primarily from lower realized product prices, lower royalties and a
gain on financial derivative instruments in 2009 compared to a loss in
2008.
 
 
 
 Production
expense
  For the
year ended December 31, 2009 production expenses decreased 14 percent to $119.4
million from $138.2 million and increased by 11 percent on a per boe basis to
$15.15 per boe from $13.64 per boe in the prior year.  The decrease in
total costs was primarily due to a decrease in production.  On a per
boe basis, the increase was primarily due to fixed costs being allocated over
fewer produced barrels of oil equivalent production.  Operating costs
in the Dixonville area continue to be incurred throughout the waterflood
expansion program.  In addition, the 2008 per boe production expense
of $13.64 benefitted from a full year of production from Southeast Saskatchewan
which incurred lower average operating costs in 2008.
  Provident
      Upstream
                    
                    Year
      ended December 31,($
      000s, except per boe data)
                    
                    2009
                    
                    
                    2008
                    
                    
                    %
      ChangeProduction
      expenses
                    
                    $
                    119,437
                    
                    
                    $
                    138,173
                    
                    
                    
                    (14
                    )Production
      expenses (per boe)
                    
                    $
                    15.15
                    
                    
                    $
                    13.64
                    
                    
                    
                    11
 Operating
netback
 
 Operating
netback as presented does not have any standardized meaning prescribed by
Canadian generally accepted accounting principles (GAAP) and may not be
comparable with calculations of similar measures of other entities.
  Provident
      Upstream
                  
                  Year
      ended December 31,($
      per boe)
                  
                  2009
                  
                  
                  2008
                  
                  
                  %
      ChangeNetback
      per boeGross
      production revenue
                  
                  $
                  37.00
                  
                  
                  $
                  65.64
                  
                  
                  
                  (44
                  )Royalties
                  
                  
                  (5.28
                  )
                  
                  
                  (12.15
                  )
                  
                  
                  (57
                  )Operating
      costs
                  
                  
                  (15.15
                  )
                  
                  
                  (13.64
                  )
                  
                  
                  11Field
      operating netback
                  
                  
                  16.57
                  
                  
                  
                  39.85
                  
                  
                  
                  (58
                  )Realized
      gain (loss) on financial derivative instruments
                  
                  
                  2.08
                  
                  
                  
                  (1.10
                  )
                  
                  
                  -Operating
      netback after realized financial derivative instruments
                  
                  $
                  18.65
                  
                  
                  $
                  38.75
                  
                  
                  
                  (52
                  )
  Provident
Upstream operating netbacks have transportation expense netted against gross
production revenue.
 
 The 2009
field operating netback of $16.57 per boe was 58 percent below the $39.85 per
boe for the prior year.  The 44 percent decrease in year over year
realized crude oil, natural gas liquids, and natural gas prices and 11 percent
higher operating costs per boe partially offset by the 57 percent decrease in
royalties on a per boe basis result in the significantly lower field operating
netback.  The 2009 operating netbacks after financial derivative
instruments decreased by 52 percent to $18.65 from $38.75 in the prior year due
to the preceding factors as well as the realized gain on financial derivative
instruments of $2.08 per boe compared to a realized loss of $1.10 per boe in the
prior year.
 
 General
and administrative
  Provident
      Upstream
                  
                  Year
      ended December 31,($
      000s, except per boe data)
                  
                  2009
                  
                  
                  2008
                  
                  
                  %
      ChangeCash
      general and administrative
                  
                  $
                  30,725
                  
                  
                  $
                  34,242
                  
                  
                  
                  (10
                  )Non-cash
      unit based compensation
                  
                  
                  3,101
                  
                  
                  
                  (2,199
                  )
                  
                  
                  -$
                  33,826
                  
                  
                  $
                  32,043
                  
                  
                  
                  6Cash
      general and administrative (per boe)
                  
                  $
                  3.90
                  
                  
                  $
                  3.39
                  
                  
                  
                  15
 
 For the
year ended December 31, 2009, cash general and administrative expenses were
$30.7 million (2008 - $34.2 million), a decrease of 10 percent.  The
decrease in cash general and administrative expenses reflected
staff
 
 
 
  reductions
and cost cutting measures implemented within the organization.  On a
per boe basis, cash general and administrative expenses in 2009 increased 15
percent to $3.90 per boe from $3.39 per boe in 2008.
 
 The
non-cash unit based compensation was an expense of $3.1 million in 2009 and a
decrease in expense of $2.2 million in 2008.  Non-cash unit based
compensation was higher in 2009 as the unit based compensation, once granted,
fluctuates based on changes in the trading prices of the Provident Trust units
which increased in 2009 over the ending trading price in 2008.
 
 Capital
expenditures
  Provident
      Upstream
                  
                  Year
      ended December 31,($
      000s)
                  
                  2009
                  
                  
                  2008Capital
      expenditures - by categoryGeological,
      geophysical and land
                  
                  $
                  4,323
                  
                  
                  $
                  25,474Drilling
      and recompletions
                  
                  
                  59,307
                  
                  
                  
                  146,992Facilities
      and equipment
                  
                  
                  25,953
                  
                  
                  
                  34,514Office
      and other
                  
                  
                  1,154
                  
                  
                  
                  2,167Total
      additions
                  
                  $
                  90,737
                  
                  
                  $
                  209,147Capital
      expenditures - by areaWest
      central Alberta
                  
                  $
                  5,547
                  
                  
                  $
                  10,326Southern
      Alberta
                  
                  
                  7,917
                  
                  
                  
                  19,852Northwest
      Alberta
                  
                  
                  36,692
                  
                  
                  
                  79,445Dixonville
                  
                  
                  26,440
                  
                  
                  
                  60,339$
                  76,596
                  
                  
                  $
                  169,962Other
      (1)
                  
                  
                  14,141
                  
                  
                  
                  39,185Total
      additions
                  
                  $
                  90,737
                  
                  
                  $
                  209,147Property
      acquisitions
                  
                  $
                  333
                  
                  
                  $
                  25,843Property
      dispositions (2)
                  
                  $
                  322,720
                  
                  
                  $
                  1,662(1)Includes Southeast Saskatchewan and Southwest Saskatchewan
      operating areas that were sold on September 30, 2009 andLloydminster
      operating area that was sold on November 30, 2009.(2)
      Property dispositions include cash proceeds on sale of assets as well as
      $17.0 million of shares in Emerge Oil & Gas Inc.received
      on sale of Lloydminster properties
   In 2009,
Provident Upstream successfully executed its capital program by spending $76.6
million on its four remaining operating areas as well as spending $12.7 million
in the year on assets that were subsequently divested.  Internal
development activities on the four remaining operating areas included 10.7 net
wells drilled for the year, including three water source wells, with a 98
percent success rate.  In addition, 4.6 net wells were drilled in
areas that were subsequently divested.  Provident’s drilling
activities in 2009 were focused on its Pekisko crude oil resource play and the
Dixonville waterflood project.  Provident spent $36.7 million in
Northwest Alberta, primarily on drilling and completion activities for the
emerging Pekisko oil resource play, which included 3.0 net wells drilled, the
infrastructure and tie-in activities associated with the 2008/2009 winter
drilling program and preparation work to start the 2009/2010 winter drilling
program.  Facility and pipeline work in Northwest Alberta included
work to provide infrastructure for the emerging Pekisko
opportunity.  Provident spent $26.4 million in Dixonville, primarily
on the waterflood program which included drilling 2.0 net wells as well as 3.0
net water source wells, completion activities, and the conversion of 21 oil
producing wells into water injectors. In Southern Alberta, $7.9 million was
primarily spent on drilling activity and recompletions, which included 2.0 net
wells drilled, and on facility upgrades and infrastructure work.  The
$5.6 million of capital in the West Central Alberta operating area was spent on
drilling, completion, tie-ins, recompletions, facility upgrades and production
optimization activities.  In addition, $1.4 million was spent on
office and non core properties.
 
 
 
 
 Depletion,
depreciation and accretion (DD&A)
  Provident
      Upstream
                  
                  Year
      ended December 31,($
      000s, except per boe data)
                  
                  2009
                  
                  
                  2008
                  
                  
                  %
      ChangeDD&A
                  
                  $
                  259,545
                  
                  
                  $
                  304,909
                  
                  
                  
                  (15
                  )DD&A
      (per boe)
                  
                  $
                  32.93
                  
                  
                  $
                  30.09
                  
                  
                  
                  9
  DD&A
charges in 2009 were down 15 percent to $259.5 million compared to $304.9
million in 2008.  The lower charges reflect reduced production volumes
compared to 2008, partially offset by an increase in the per boe DD&A
rate.  The rate of $32.93 per boe increased nine percent for 2009
compared to $30.09 per boe in 2008.  The per boe increase was
primarily as a result of 2008 and 2009 capital expenditures on longer term
projects at Dixonville and the Pekisko play in Northwest Alberta.  In
the short term, these expenditures add costs to the depletable base without the
addition of further proved reserves.  The addition of more proved
reserves associated with these projects would have a favourable impact on
DD&A per boe.
 
 In 2009,
DD&A also includes accretion expense associated with asset retirement
obligation of $3.1 million (2008 - $3.4 million).
 
 
 
 
 Provident
Midstream business segment review
  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:
  Empress
East
 Redwater
West
 Commercial
Services
 
 The
Empress East business line is comprised of the following core
assets:
 
 ·
                Approximately
      2.0 Bcfd in 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, 33.0 percent ownership in the 2.7
      Bcfd capacity BP Empress 1 Plant, 12.4 percent ownership in the 1.1 Bcfd
      capacity ATCO Plant and 8.3 percent ownership in the 2.4 Bcfd capacity
      Spectra 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 of NGLs into the Enbridge pipeline
      system.  Along the Enbridge pipeline system in Superior,
      Wisconsin, Provident holds an 18.3 percent ownership of a 300,000 barrel
      storage staging facility and 18.3 percent ownership of a 6,600 bpd
      depropanizer.
 
 ·
                In
      Sarnia, Ontario, 16.5 percent ownership of an approximately 150,000 bpd
      fractionator, 1.7 mmbbl of raw product storage capacity, and 18.0 percent
      of 5.0 mmbbl of finished product storage and a rail, truck and pipeline
      terminalling facility.  An additional 500,000 bbls of
      specification product storage is also leased in the Sarnia
      area.
 
 ·
                A
      propane distribution terminal at Lynchburg,
  Virginia.
 
 ·
                A
      rail car fleet of approximately 300 rail cars under long-term lease
      agreement.
 
 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, seven million gross barrels of
      salt cavern storage, and a 75,000 bpd condensate rail offloading facility
      with a 500 railcar storage yard.  The Redwater facility is the
      only facility in western Canada that can fractionate a high-sulphur
      ethane-plus mix.
 
 ·
                Approximately
      7,000 bpd of leased fractionation 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 fractionation facility 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 pipeline system that extends the product
      delivery transportation network through to the Redwater fractionation
      facility.
 
 ·
                A
      rail car fleet of approximately 700 rail cars under long-term lease
      agreement.
  
 The
Empress East and Redwater West business lines are supported by Provident’s
integrated marketing arm which has offices in Calgary, Alberta, Sarnia, Ontario,
and Houston, Texas and operates under the brand name Kinetic. Rather than
selling NGL produced by the Empress East and Redwater West facilities at the
plant gate, the marketing and logistics group utilizes Provident’s integrated
suite of transportation, storage and logistics assets to access markets across
North America.  Due to its broad marketing scope, Provident’s NGL
products are priced based on multiple pricing indices.  These indices
generally correspond with the four major NGL trading hubs in North America which
are located in Mont Belvieu, Texas, Conway, Kansas, Edmonton, Alberta, and
Sarnia, Ontario.  Mont Belvieu, the largest NGL trading center, serves
as the reference point for NGL pricing in North America.  By
strategically building inventories of specification products which are then
distributed into premium-priced markets across North America during periods of
high seasonal demand, Provident is able to optimize the margins it earns from
its extraction and fractionation operations. Provident’s marketing group also
generates margins by taking advantage of locational price differentials and
arbitrage trading opportunities. Margins generated through marketing activities
are included within the Empress East and Redwater West business
lines.
 
 The
Commercial Services business line:
 
 The
Commercial Services business line includes services such as fractionation,
storage, LPG terminalling, loading and offloading that are provided to third
parties at Provident’s Redwater facility on a fee basis.  Year over
year, Provident has significantly enhanced its Commercial Services platform at
Redwater by adding incremental terminalling capacity at its condensate rail
terminal and, most recently, through the addition of condensate storage
capabilities.  During the third quarter of 2009, two new 500,000
barrel storage caverns at Redwater were placed into condensate service, and a
third condensate storage cavern is currently under construction.  The
Commercial Services business line 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.  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 price volatility and are thus relatively stable.
 
 Long
term contracts
 
 At the
Redwater fractionation facility, a significant portion of the available propane,
butane and condensate (“propane-plus”) fractionation capacity is contracted
through a long term fee for service arrangement with third parties.
 
 The
ethane produced from Provident’s facilities at Empress and Redwater is largely
sold under long term contracts.
 
 In 2006
and early 2007, Provident commissioned a condensate rail off-loading terminal at
Redwater with current capacity of 75,000 bpd, a significant portion of which is
under long term contracts with two major energy producers.
 
 Provident
has two 500,000 barrel caverns used for condensate storage at
Redwater.  The majority of the condensate storage capacity is sold
under long term contracts to various third parties, a number of which are major
energy producers, with terms averaging from two to five years.
 
 Provident
has a long term contract on a cost of service basis for the majority of its
50,000 bbl/d Empress debutanizer facility with a major energy
producer.
 
 Market
environment
 
 Performance
of the Midstream business unit is closely tied to market prices for NGL products
and natural gas, which can vary significantly from period to
period.  The key reference prices impacting Midstream operating
margins are summarized in the following table:
  Midstream
      business reference prices
                  
                  Year
      ended December 31,2009
                  
                  
                  2008
                  
                  
                  %
      ChangeWTI
      (US$ per barrel)
                  
                  $
                  61.80
                  
                  
                  $
                  99.65
                  
                  
                  
                  (38
                  )Exchange
      rate (from US$ to Cdn$)
                  
                  
                  1.14
                  
                  
                  
                  1.07
                  
                  
                  
                  7WTI
      expressed in Cdn$ per barrel
                  
                  $
                  70.54
                  
                  
                  $
                  106.33
                  
                  
                  
                  (34
                  )AECO
      monthly index (Cdn$ per gj)
                  
                  $
                  3.92
                  
                  
                  $
                  7.71
                  
                  
                  
                  (49
                  )Frac
      Spread Ratio (1)
                  
                  
                  18.0
                  
                  
                  
                  13.8
                  
                  
                  
                  30Mont
      Belvieu Propane (US$ per US gallon)
                  
                  $
                  0.84
                  
                  
                  $
                  1.41
                  
                  
                  
                  (40
                  )Mont
      Belvieu Propane expressed as a percentage of WTI
                  
                  
                  57
                  %
                  
                  
                  60
                  %
                  
                  
                  (5
                  )Market
      Frac Spread in Cdn$ per barrel (2)
                  
                  $
                  28.61
                  
                  
                  $
                  35.35
                  
                  
                  
                  (19
                  )1)Frac spread ratio is the ratio of WTI expressed in Canadian dollars
      per barrel to the AECO monthly index (Cdn$ per gj).2) Market
      frac spread is determined using weighted average spot prices at Mont
      Belvieu for propane, butane, and condensate andthe
      AECO monthly index price for natural gas.
    
 Market
conditions created a challenging environment for NGL operations in 2009. WTI
crude oil prices averaged US$61.80 per barrel in 2009 as compared to US$99.65
per barrel in 2008, a 38 percent reduction.  WTI crude prices, which
largely drive NGL pricing, declined sharply in the last quarter of 2008 in
response to the slowing world economy.  This decline continued into
2009 when WTI prices fell below US$35.00 per barrel during the first quarter of
2009 before recovering to an average of US$76.19 per barrel in the fourth
quarter.  This is in stark contrast to the first nine months of 2008
where WTI prices reached record levels of over US$140 per barrel. Propane prices
relative to WTI were also lower in 2009 with Mont Belvieu propane averaging 57
percent of WTI as compared to 60 percent of WTI in 2008.  Propane
prices relative to WTI were lowest during the second and third quarters of 2009
as a result of weaker product demand and above average levels of propane
inventory in the North American marketplace.
 
 Natural
gas prices were also significantly impacted by the economic slow
down.  AECO natural gas prices averaged $3.92 per gj in 2009 as
compared to $7.71 per gj in 2008, and reached lows of below $2.00 per gj during
the month of September before recovering to exit the year at approximately $5.50
per gj.  While lower natural gas prices are generally favorable to NGL
extraction and fractionation economics, a sustained period in a low price
environment can have an adverse impact on the availability and cost of natural
gas and NGL mix supply if natural gas producers elect to shut-in production or
reduce drilling activities.  The impact of lower supply could be
partially mitigated through an increase in NGL prices if demand for product
exceeds available supply.
 
 Market
frac spreads, a key driver of NGL extraction economics, averaged $28.61 per
barrel in 2009 as compared to $35.35 per barrel in 2008. Lower market frac
spreads were the result of lower NGL prices, offset by much lower prices for
natural gas. Extraction premiums paid to acquire the natural gas also have an
impact on NGL extraction economics.  While extraction premiums are
excluded from the calculation of market frac spreads, they are included, along
with other costs, when determining actual extraction operating
margins.  Over the past several months, Empress extraction premiums
significantly increased as a result of reduced volumes of natural gas flowing
past the Empress straddle plants.  During 2009, natural gas throughput
at the Empress Eastern border averaged approximately 5.2 bcf per day, a decrease
of approximately 17 percent compared to the prior year.  Lower natural
gas throughput at the Empress facilities reduced propane-plus inventories
currently available for sale in Sarnia and in surrounding eastern
markets.  In 2010, as available propane-plus supply tightens relative
to demand, pricing differentials in these eastern markets where Provident sells
the majority of its Empress East production, may increase relative to other
major propane hubs including Mont Belvieu and Conway.
  At the
end of 2009, industry propane inventories in the United States were
approximately 49 million barrels, a decrease of 11 percent compared to the prior
year, and approximately seven million barrels below the five year historical
average.  For most of 2009, United States industry propane inventories
exceeded the five year average, peaking at over 18 million barrels above the
five year average during the month of June.  United States industry
propane inventories have fallen significantly since that period, driven
primarily by above average propane withdrawals during the fourth quarter and the
start of the winter heating season.  Ending 2009 Canadian
industry
 
 
 
 propane
inventories of approximately five million barrels were in-line with the prior
year, but lower than the five year average of approximately six million
barrels.
 
 Midstream
business performance
 
 Midstream
business unit results can be summarized as follows:
  Year
      ended December 31,(bpd)
                  
                  2009
                  
                  
                  2008
                  
                  
                  %
      ChangeProvident
      Midstream NGL sales volumes
                  
                  
                  113,528
                  
                  
                  
                  119,649
                  
                  
                  
                  (5
                  )
  Year
      ended December 31,($
      000s)
                  
                  2009
                  
                  
                  2008
                  
                  
                  %
      ChangeEmpress
      East Margin
                  
                  $
                  95,633
                  
                  
                  $
                  157,976
                  
                  
                  
                  (39
                  )Redwater
      West Margin
                  
                  
                  127,404
                  
                  
                  
                  142,836
                  
                  
                  
                  (11
                  )Commercial
      Services Margin
                  
                  
                  63,746
                  
                  
                  
                  46,541
                  
                  
                  
                  37Gross
      operating margin
                  
                  
                  286,783
                  
                  
                  
                  347,353
                  
                  
                  
                  (17
                  )Realized
      loss on financial derivative instruments
                  
                  
                  (66,743
                  )
                  
                  
                  (118,917
                  )
                  
                  
                  (44
                  )Cash
      general and administrative expenses
                  
                  
                  (31,297
                  )
                  
                  
                  (33,845
                  )
                  
                  
                  (8
                  )Strategic
      review and restructuring expenses
                  
                  
                  (4,624
                  )
                  
                  
                  (1,683
                  )
                  
                  
                  175Foreign
      exchange (loss) gain and other
                  
                  
                  (1,802
                  )
                  
                  
                  19,853
                  
                  
                  
                  -Provident
      Midstream EBITDA
                  
                  $
                  182,317
                  
                  
                  $
                  212,761
                  
                  
                  
                  (14
                  )
  Gross
operating margin
 
 Midstream
gross operating margin was $286.8 million for the year ended December 31, 2009
compared to $347.4 million in 2008.  The 17 percent decrease was due
to lower operating margins from the Empress East and Redwater West business
lines, partially offset by a 37 percent increase in contribution from the
Commercial Services business line.
 
 The
Empress East business line:
 
 The
Empress East business line extracts NGLs from natural gas at the Empress
straddle plants and sells finished products into markets in central Canada and
the eastern United States.  Demand for propane is seasonal and results
in inventory that generally builds over the second and third quarters of the
year and is sold in the fourth quarter and the first quarter of the following
year.  The margin in this business is determined primarily by the
“frac spread”, which represents the difference between the selling prices for
propane-plus and the input cost of the natural gas required to produce the
respective NGL products.  The frac spread can change significantly
from period to period depending on the relationship between crude oil and
natural gas prices (the “frac spread ratio”), absolute commodity prices, and
changes in the Canadian to US dollar foreign exchange
rate.  Traditionally a higher frac spread ratio and higher crude oil
prices will result in stronger business line margins.  Differentials
between propane-plus and crude oil prices, as well as locational price
differentials will also impact the frac spread.  Natural gas
extraction premiums and costs relating to transportation, fractionation, storage
and marketing are not included within the frac spread, however these costs are
included in the business line operating margin.
 
 In 2009,
the gross operating margin for Empress East was $95.6 million (2008 - $158.0
million), a reduction of 39 percent.  Lower operating margins were the
result of lower realized propane-plus unit margins and a 19 percent decrease in
propane-plus sales volumes.  Realized per unit margins have decreased
from the prior year due to lower frac spreads which are reflective of the market
pricing environment.  Per unit margins were also impacted by an
increase in natural gas extraction premiums, particularly during the second half
of 2009. In recent months, extraction premiums more than doubled as a result of
lower eastern gas flows through the Empress facilities.  Eastern gate
gas
 
 
 supply
has been impacted in 2009 by lower natural gas drilling activity in western
Canada, shut-in production, and narrower natural gas pricing differentials
between AECO and Chicago.
 
 The 19
percent decrease in sales volumes was the result of lower propane-plus term
sales and lower product availability. In the beginning of 2009, Provident
reduced its term sales commitments for the upcoming NGL contract year as a
result of the pending expiry of its fractionation capacity lease at Sarnia on
the first of April 2009, which was expected to reduce Empress East processing
capacity by 6,000 bpd during the 2009/10 NGL year which runs from April, 2009
through to March, 2010.  In August, Provident was successful in
restoring this reduced capacity by purchasing approximately 7,400 bpd of
additional fractionation capacity at Sarnia.  As Provident moves into
2010, it expects to realize additional benefits from the incremental capacity,
particularly as new term sales arrangements are negotiated for the upcoming NGL
contract year which begins on April 1, 2010.  Full realization of the
benefits of the incremental capacity at Sarnia will be impacted by the
availability and cost of supply at Empress.
 
 The
Redwater West business line:
 
 The
Redwater West business line purchases an NGL mix from various producers and
fractionates it into finished products at the Redwater fractionation facility
near Edmonton, Alberta.  Because the feedstock for this business line
is primarily NGL mix rather than natural gas, the frac spread has a smaller
impact on margin than in the Empress East business line.The Redwater facility also
has the largest and industry-leading rail-based condensate terminal in western
Canada which serves the heavy oil industry and its need for
diluent.  Income generated from the condensate terminal and caverns
which relates to third-party terminalling and storage is included within the
Commercial Services business line, while income relating to proprietary
condensate marketing activities remains within the Redwater West business
line.
 
 In 2009,
the operating margin for Redwater West was $127.4 million (2008 - $142.8
million) a decrease of 11 percent.  The decrease was primarily a
result of lower margins from ethane and condensate sales, partially offset by
higher margins on propane.  Ethane margins were lower than in the
prior year as a result of lower sales volumes and lower per unit margins, which
were impacted by lower sales prices and by month over month falling natural gas
prices during the first three quarters of 2009.  The decrease in
condensate margins was the result of lower realized per unit margins.
Incremental demand for condensate for use as diluent was much stronger in 2008
which resulted in much higher premiums relative to WTI being paid for condensate
in the Edmonton marketplace.  Condensate premiums relative to WTI in
the Edmonton area averaged approximately US$6.00 per bbl in 2008 as compared to
a discount of approximately US$0.80 per bbl in 2009.  Margins earned
from propane sales were higher than in the prior year predominantly as a result
of the stronger pricing environment in the fourth quarter of 2009 relative to
the fourth quarter of 2008.  Butane margins in 2009 were similar to
the prior year with higher per unit margins offsetting lower sales
volumes.  On a combined basis, Redwater West propane-plus selling
prices decreased by 34 percent relative to the prior year reflecting the decline
in average market prices for NGL.  Cost of goods sold, on a per unit
basis, were 39percent lower
than 2008 reflecting lower market prices for NGL and natural gas
supply.
 
 Propane-plus
volumes were three percent lower than in the prior year primarily as a result of
lower butane sales. Lower butane sales were the result of changing market
conditions, which impacted the availability of butane supply.  Propane
and condensate sales volumes were similar to the prior year.
  The
Commercial Services business line:
 
 The
Commercial Services business line generates income from fee-for-service
contracts to provide fractionation, storage, LPG terminalling, loading and
offloading services.  The growth in this business segment has been
primarily driven by the expansion of Provident’s condensate terminalling and
storage facilities at Redwater.  Income from pipeline tariffs from
Provident’s ownership in NGL pipelines is also included in this business
line.  In 2009, the margin for this business line was $63.7 million
(2008 - $46.5 million).  The 2009 operating margin was 37 percent
higher than 2008 mostly due to increased fee based revenues associated with the
condensate terminalling facility, higher third party processing fees and
incremental storage revenues from Provident’s condensate storage caverns which
were placed into service during the third quarter.
 
 
 
 
 Operations
– Midstream NGL sales volumes
 
 Provident
Midstream sold 113,528 bpd in 2009, down five percent when compared with 119,649
bpd in 2008.  The reduction in volumes primarily represents the
decrease in propane-plus volumes in both Empress East and Redwater
West.
 
 Earnings before interest, taxes,
depletion, depreciation, accretion, and other non-cash items (“adjusted
EBITDA”) and funds flow
from operations
 
 For 2009,
adjusted EBITDA decreased 14 percent to $182.3 million from $212.8 million in
2008 reflecting lower operating margins for the Empress East and Redwater West
business lines, partially offset by a lower realized loss on financial
derivative instruments and lower cash general and administrative
expenses.  The $66.7 million realized loss on financial derivative
instruments was driven by natural gas derivative purchase contracts that settled
at current market prices that were lower than the original derivative contract
prices.  The comparable 2008 amounts had a larger realized loss on
financial derivative instruments, driven primarily by crude oil derivative sales
contracts settling at prices considerably higher than the original derivative
contract crude oil prices.  The 2008 adjusted EBITDA amount also
included gains on corporate foreign exchange contracts settled in the period, of
which $20.1 million was allocated to the Midstream segment and was included in
foreign exchange (loss) gain and other. Cash general and administrative expenses
were lower in 2009 as a result of staff reductions and cost cutting measures
implemented within the organization.  Funds flow from operations for
2009 was $161.8 million, a decrease of $17.2 million or 10 percent compared to
$179.0 million in 2008.  The decrease in funds flow from operations
reflects the lower adjusted EBITDA, partially offset by significantly lower
interest expense.
 
 Capital
expenditures
 
 Provident
Midstream capital expenditures for 2009 totaled $36.6 million.  In
2009, $31.1 million was spent primarily on the continued development of cavern
storage, the condensate terminalling and storage facility and pre-development
activities relating to the Michigan depropanizer.  In addition, $2.7
million was spent on sustaining capital requirements, $2.1 million was added to
capitalized linefill and $0.7 million was spent on office related
capital.
 
 Midstream
asset acquisitions
 
 On August
12, 2009, Provident purchased an additional 6.15 percent interest in the Sarnia
fractionation facilities for $14.8 million and a deferred payment of $3.7
million for a facility enhancement planned for 2010.  This acquisition
increased Provident’s ownership in the Sarnia fractionator, effective August 1,
2009, to approximately 16.5 percent, increasing propane-plus fractionation
capacity in the Empress East system by approximately 7,400 bpd to 20,000 bpd in
total.  This acquisition replaced the 6,000 bpd of formerly leased
capacity at Sarnia that expired on April 1, 2009.  As a result of this
transaction, Provident has deferred construction of its previously announced
depropanizer facility in Michigan.
 
 In
November 2009, Provident announced an agreement to purchase a commercial storage
facility in Corunna, Ontario for an undisclosed amount.  The facility
is located in close proximity to Provident’s existing operations in Sarnia,
Ontario.  The 1,000 acre site has an active cavern storage capacity of
12.1 million barrels, consisting of 5.0 million barrels of hydrocarbon storage
and 7.1 million barrels currently used for brine storage.  The
facility also includes 13 pipeline connections and a small rail offloading
facility.  The transaction is expected to close by the end of the
second quarter of 2010.
 
 
 
 Discontinued
operations (USOGP)
 
 In
February, 2008 the Trust announced a strategic process respecting the decision
to dispose of the operations that comprise the United States oil and natural gas
production (USOGP) business.  Effective in the first quarter of 2008,
Provident’s USOGP business was accounted for as discontinued
operations.  The USOGP business was sold in June and August of
2008.
 
 Quicksilver
Resources Inc. ("Quicksilver") filed a lawsuit on October 31, 2008 against
BreitBurn Energy Partners, L.P. (the MLP), certain of its directors (including
three Provident nominees), and Provident.  The MLP was part of the
USOGP business.  The claim relates to a transaction between the MLP
and Quicksilver and certain other MLP matters. Quicksilver alleges, among other
things, that it was induced to enter into a contribution agreement pursuant to
which it contributed assets to the MLP by false representations as to
Provident’s relationship with the MLP. The transaction involved the issuance by
the MLP to Quicksilver of approximately U.S. $700 million of units of the
MLP.   In February 2010, Provident agreed to settle all existing
litigation with Quicksilver.  Provident expects the cost of the
lawsuit and settlement will be covered by insurance.
 
 
 Disclosure
Controls and Procedures:  U.S. Sarbanes-Oxley Act
 
 In 2002,
the United States Congress enacted the Sarbanes-Oxley Act (SOX), which requires
that issuers that are required to file reports with the United States Securities
and Exchange Commission must assess and report upon the effectiveness of their
“internal control over financial reporting” as of the end of each fiscal
year.  As an entity listed on the New York Stock Exchange, Provident
is subject to the rules.  See “Management’s Report on Internal Control
Over Financial Reporting” and “Independent Auditors’ Report”.
 
 As of
December 31, 2009, an evaluation of the effectiveness of Provident’s “disclosure
controls and procedures” (as such term is defined in Rules 13a-15(e) and
15d-15(e) of the United States Securities Exchange Act of 1934, as amended (the
“Exchange Act”)) was carried out by the management of Provident, with the
participation of the Chief Executive Officer (“CEO”) and Chief Financial Officer
(“CFO”).  Based upon that evaluation, the CEO and CFO have concluded
that as of December 31, 2009, Provident’s disclosure controls and procedures are
effective to ensure that information required to be disclosed by Provident in
reports that it files or submits to Canadian and United States securities
authorities are (i) recorded, processed, summarized and reported within the time
periods specified by Canadian and Unites States securities laws and (ii)
accumulated and communicated to Provident’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 Provident’s disclosure controls
and procedures provide a reasonable level of assurance that they are effective,
they do not expect that Provident’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.
 
 Provident
will continue to periodically evaluate its disclosure controls and procedures
and internal controls over financial reporting and will make modifications from
time to time as deemed necessary.
 
 During
the year ended December 31, 2009, there were no changes in Provident’s internal
control over financial reporting that have materially affected, or are
reasonably likely to materially affect, Provident’s internal control over
financial reporting.
 
 
 Foreign
ownership
 
 Based on
information received from our transfer agent and financial intermediaries in
January 2010, 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 estimates
 
 Provident’s
significant accounting policies are described in note 2 to the consolidated
financial statements. Certain accounting policies include critical accounting
estimates.  These policies 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.
 
 The
Trust’s financial and operating results incorporate certain estimates
including:
  ·
                depletion,
      depreciation and accretion based on estimated oil and gas
      reserves;
 ·
                future
      recoverable value of property, plant and equipment and goodwill (see
      “Goodwill and intangible assets”) based on estimated future cash
      flows;
 ·
                value
      of asset retirement obligations based on estimated future costs and timing
      of expenditures;
 ·
                fair
      values of derivative contracts that are subject to fluctuation depending
      upon underlying commodity prices and foreign exchange rates (see note 14
      to the consolidated financial statements);
and
 ·
                income
      taxes based on estimates of future income and tax pool claims (see
      “Taxes”).
 
 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
and accumulated in one cost centre as all of the oil and natural gas assets are
in Canada.  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 the assets are tested by comparing
the carrying value to the sum of the undiscounted cash flows
expected.  If the carrying value is not recoverable the assets are
written down to their 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. and AJM Petroleum Consultants, independent
engineering firms, to evaluate Provident’s 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.
 
 The ARO
standard requires that management make estimates and assumptions regarding
future liabilities and cash flows involving environmental reclamation and
remediation.  Such assumptions are inherently uncertain and subject to
change over time due to factors such as historical experience, changes in
environmental legislation or improved technologies.  Changes in
underlying assumptions, based on the above noted factors, could have a material
impact on Provident’s financial results.
 
 
 Change
in accounting policies
 
 (i)
                Goodwill
      and intangible assets
 
 In the
first quarter of 2009, the Trust adopted CICA Handbook section 3064 “Goodwill
and Intangible assets” which supersedes section 3062 “Goodwill and other
Intangible assets” and section 3450 “Research and Development”.  This
new section established standards for the recognition, measurement and
disclosure of goodwill and intangible assets.  The adoption of this
standard did not have a material impact on the Trust’s consolidated financial
statements.
 
 (ii)
                Business
      combinations
 
 In
December of 2008, the CICA released Handbook section 1582 “Business
Combinations”, which replaces existing guidance under section 1581 “Business
Combinations”.  The new standard is intended to converge with
International Financial Reporting Standards.  Under section 1582, the
purchase price in a business combination is based on the fair value of shares
exchanged at the market price on the acquisition date.  Under the
existing standard, the purchase price is based on the market price of shares
over a reasonable period before and after the date of acquisition is agreed upon
and announced.  This new standard also requires that all acquisition
costs be expensed as incurred.  Currently, these costs may be
capitalized as part of the purchase price.  In addition, the new
guidance addresses contingent liabilities, which will be required to be
recognized at fair value on acquisition and subsequently remeasured at each
reporting period until settled.  Under the current standard, only
contingent liabilities that are payable are recognized.  This new
section requires that negative goodwill to be recognized in earnings immediately
rather than the existing standard of reducing non-current assets in the purchase
price allocation.  The new standard applies prospectively to business
combinations on or after January 1, 2011 with earlier adoption
permitted.  The Trust is currently assessing the impact of the new
standard.
 
 (iii)
                International
      Financial Reporting Standards
(IFRS)
 
 During
2008, the Canadian Accounting Standards Board (AcSB) confirmed that publicly
accountable enterprises will be required to adopt International Financial
Reporting Standards (IFRS) in place of Canadian GAAP for interim and annual
reporting purposes.  The required changeover date is for fiscal years
beginning on or after January 1, 2011.
 
 In 2008,
Provident commenced the process to transition from current Canadian GAAP to
IFRS.  A project plan and a project team were
established.  The project team is led by finance management and
includes representatives from various areas of the organization as necessary to
plan for a smooth transition to IFRS.
  
 
 The
project plan consists of three phases: initiation, detailed assessment and
design and implementation.  Provident has completed the first phase,
which involved the development of a detailed timeline for assessing resources
and training and the completion of a high level review of the major differences
between current Canadian GAAP and IFRS.  Education and training
sessions for employees throughout the organization and discussions with
Provident’s external auditors have been held and will continue throughout the
subsequent phases.  Regular reporting on the project plan is provided
to Provident’s senior management and to the Audit Committee of the Board of
Directors.
 
 During
2009, Provident was engaged in the detailed assessment and design phase of the
project.  The detailed assessment and design phase involves a
comprehensive analysis of the impact of the IFRS differences identified in the
initial scoping assessment.  In addition, an initial evaluation of
IFRS 1 transition exemptions, as further described below, and an analysis of
financial systems has been performed.
 
 During
the implementation phase which began in the first quarter of 2010, Provident
will execute the required changes to business processes, financial systems,
accounting policies, IT systems, disclosure controls and internal controls over
financial reporting as discussed below.  Management has not yet
finalized its accounting policies and as such is unable to quantify the impact
of adopting IFRS on the financial statements.  In addition, due to
anticipated changes to IFRS and International Accounting Standards prior to
Provident’s adoption of IFRS, management’s plan is subject to change based on
new facts and circumstances that arise after the date of this
MD&A.
 
 First
–Time Adoption of IFRS:
 
 IFRS 1,
“First-Time Adoption of International Financial reporting Standards” (“IFRS 1”),
provides entities adopting IFRS for the first time with a number of optional
exemptions and mandatory exceptions in certain areas to the general requirement
for full retrospective application of IFRS.  Management is analyzing
the various accounting policy choices available and will implement those
determined to be the most appropriate for Provident, which at this time include
the following:
 
 ·
                Business
      Combinations – IFRS 1 would allow Provident to use the IFRS rules for
      business combinations on a prospective basis rather than re-stating all
      business combinations that occurred prior to transition to
      IFRS.  The IFRS business combination rules converge with the new
      CICA Handbook section 1582 that is also effective for Provident on January
      1, 2011, however, early adoption is
permitted.
 
 ·
                Property,
      Plant and Equipment (“PP&E”) – IFRS 1 provides the option to value the
      Upstream PP&E assets at their deemed cost being the Canadian GAAP net
      book value assigned to these assets as at the date of transition, January
      1, 2010.  This amendment is permissible for entities, such as
      Provident, who currently follow the full cost accounting guideline under
      Canadian GAAP that accumulates all oil and gas assets into one cost
      centre.  Under IFRS, Provident’s PP&E assets must be divided
      into smaller cost centres.  The net book value of the assets on
      the date of transition will be allocated to the new cost centres on the
      basis of Provident’s reserve volumes or values at that point in
      time.
 
 The
transition from Canadian GAAP to IFRS is a significant undertaking that may
materially affect the Trust’s reported financial position and results of
operations.  At this time, Provident has identified key differences
that will impact the financial statements as follows:
 
 ·
                Presentation
      of Exploration and Evaluation (“E&E”) expenditures separate from
      PP&E – Upon transition to IFRS, Provident will present all E&E
      expenditures as a separate component on the Consolidated Balance
      Sheet.  This will include the book value for Provident’s land
      that relates to undeveloped properties.  E&E assets will not
      be depleted and must be assessed for impairment when indicators suggest
      the possibility of impairment.
 
 ·
                Calculation
      of depletion expense for Upstream PP&E assets – Upon transition to
      IFRS, Provident has the option to calculate depletion using a reserve base
      of proved reserves or both proved and probable reserves, as compared to
      the Canadian GAAP method of calculating depletion using only proved
      reserves.  Provident has not concluded at this time which method
      for calculating depletion will be
used.
  
 ·
                Impairment
      of long-term assets – Under IFRS, impairment of long-term assets must be
      calculated at a more granular level than what is currently required under
      Canadian GAAP.  Impairment calculations will be performed at the
      cash generating unit level for both Upstream and Midstream long-term
      assets.
 
 ·
                Due
      to the recent withdrawal of the exposure draft on IAS 12 Income Taxes in
      November 2009 and the issuance of the exposure draft on IAS 37 Provisions,
      Contingent Liabilities and Contingent Assets in January
      2010,  management is still determining the impact of these
      revised standards on its IFRS
transition.
 
 In
addition to accounting policy differences, Provident’s transition to IFRS will
impact the internal controls over financial reporting, disclosure controls and
procedures and IT systems as follows:
 
 ·
                Internal
      controls over financial reporting – As the review of Provident’s
      accounting policies is completed, an assessment will be made to determine
      changes required to ensure the continued integrity of Provident’s internal
      controls over financial reporting.  As an example, additional
      controls will be implemented for the IFRS 1 changes such as the allocation
      of Provident’s PP&E as well as the process for re-classifying
      Provident’s E&E expenditures from PP&E.  This assessment
      will be an ongoing process through 2010 to ensure that all changes in
      accounting policies include the appropriate additional controls and
      procedures for future IFRS reporting
  requirements.
 
 ·
                IT
      systems – Provident is finalizing the system updates required in order to
      ready the Trust for IFRS reporting.  The modifications while not
      significant are, however, deemed critical in order to allow for reporting
      of both Canadian GAAP and IFRS statements in 2010 as well as the
      modifications required to track PP&E costs and E&E costs with a
      more granular level of detail for IFRS reporting.  Additional
      system modifications may be required based on final policy
      choices.
 
 ·
                Disclosure
      controls and procedures – Information relating to Provident’s transition
      to IFRS, as well as the progress in completing the implementation phase
      described above, will continue to be communicated to senior management and
      the Board of Directors and reported on in Provident’s annual and interim
      filings, including its MD&A.   As a result, Provident’s
      disclosure controls and procedures will ensure that stakeholders are
      provided with sufficient information to assist in understanding the impact
      of the IFRS transition on
Provident.
 
 
 Business
risks
 
 The trust
industry is subject to risks that can affect the amount of funds flow from
operations available for distribution to unitholders, and the ability to
grow.  These risks include but are not limited to:
  ·
                capital
      markets, credit and liquidity risks and the ability to finance future
      growth; and
  ·
                the
      impact of Canadian governmental regulation on Provident, including the
      effect of the legislated tax on trust
  distributions.
 
 The oil
and natural gas industry is subject to numerous risks that can affect the amount
of cash flow available for distribution to unitholders and the ability to
grow.  These risks include but are not limited to:
  ·
                fluctuations
      in commodity price, exchange rates and interest
  rates;
  ·
                government
      and regulatory risk in respect of royalty and income tax
      regimes;
  ·
                changes
      to environmental regulations;
  ·
                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;
  
  ·
                competition
      for exploration prospects and the development of new sources of
      production;
  ·
                declining
      oil and natural gas reserves and
production;
  ·
                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;
  ·
                reduction
      in the volume of throughput or the level of
  demand;
  ·
                the
      ability to attract and retain
employees;
  ·
                increasing
      operating and capital costs;
  ·
                regulatory
      intervention in determining processing fees and tariffs;
    and
  ·
                reliance
      on significant customers.
  Provident
strives to minimize these business risks by:
  ·
                employing
      and empowering management and technical staff with extensive industry
      experience and providing competitive
  remuneration;
  ·
                adhering
      to a strategy of acquiring, developing and optimizing quality, low-risk
      reserves in areas where we have technical and operational
      expertise;
  ·
                developing
      a diversified, balanced asset portfolio that generally offers developed
      operational infrastructure, year-round access and close proximity to
      markets;
  ·
                adhering
      to a disciplined Commodity Price Risk Management Program to mitigate the
      impact that volatile commodity prices have on cash flow available for
      distribution;
  ·
                marketing
      crude oil and natural gas to a diverse group of customers, including
      aggregators, industrial users, well-capitalized third-party marketers and
      spot market buyers;
  ·
                marketing
      natural gas liquids and related services to selected, credit worthy
      customers at competitive rates;
  ·
                maintaining
      a competitive cost structure to maximize cash flow and
      profitability;
  ·
                maintaining
      prudent financial leverage and developing strong relationships with the
      investment community and capital
providers;
  ·
                adhering
      to strict guidelines and reporting requirements with respect to
      environmental, health and safety practices;
and
  
  ·
                maintaining
      an adequate level of property, casualty, comprehensive and directors’ and
      officers’ insurance coverage.
 
 Readers
should be aware that the risks set forth herein are not
exhaustive.  Readers are referred to Provident’s annual information
form, which is available at www.sedar.com, for a
detailed discussion of risks affecting Provident.
 
 Unit
trading activity
 
 The
following table summarizes the unit trading activity of the Provident units for
each of the four quarters in the year ended December 31, 2009 on both the
Toronto Stock Exchange and the New York Stock Exchange:
  Q1
                  
                  
                  
                  Q2
                  
                  
                  
                  Q3
                  
                  
                  
                  Q4TSE
      – PVE.UN (Cdn$)High
                  
                  $
                  6.61
                  
                  
                  $
                  6.50
                  
                  
                  $
                  6.46
                  
                  
                  $
                  7.36Low
                  
                  $
                  2.90
                  
                  
                  $
                  4.50
                  
                  
                  $
                  4.69
                  
                  
                  $
                  5.64Close
                  
                  $
                  4.81
                  
                  
                  $
                  5.82
                  
                  
                  $
                  6.20
                  
                  
                  $
                  7.08Volume
      (000s)
                  
                  
                  21,878
                  
                  
                  
                  22,810
                  
                  
                  
                  17,610
                  
                  
                  
                  18,346NYSE
      – PVX  (US$)High
                  
                  $
                  5.60
                  
                  
                  $
                  5.70
                  
                  
                  $
                  6.08
                  
                  
                  $
                  6.99Low
                  
                  $
                  2.23
                  
                  
                  $
                  3.55
                  
                  
                  $
                  4.00
                  
                  
                  $
                  5.19Close
                  
                  $
                  3.72
                  
                  
                  $
                  4.92
                  
                  
                  $
                  5.76
                  
                  
                  $
                  6.72Volume
      (000s)
                  
                  
                  92,576
                  
                  
                  
                  83,525
                  
                  
                  
                  72,040
                  
                  
                  
                  103,991
 
 Forward-looking
information
  This
MD&A contains forward-looking information under applicable securities
legislation.  Statements which include forward-looking information
relate to future events or the Trust's future performance.  Such
forward-looking information is provided for the purpose of providing information
about management's current expectations and plans relating to the
future.  Readers are cautioned that reliance on such information may
not be appropriate for other purposes, such as making investment
decisions.  All statements other than statements of historical fact
are forward-looking information.  In some cases, forward-looking
information can be identified by terminology such as "may", "will", "should",
"expect", "plan", "anticipate", "believe", "estimate", "predict", "potential",
"continue", or the negative of these terms or other comparable
terminology.  Statements relating to "reserves" or "resources" are
deemed to be forward-looking information, as they involve the implied
assessment, based on certain estimates and assumptions, that the resources and
reserves described can be profitably produced in the future.  Forward
looking information in this MD&A includes, but is 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.  Specifically, the “Outlook” section in this MD&A may
contain forward-looking information about prospective results of operations,
financial position or cash flows of the Trust.  Forward-looking
information is based on current expectations, estimates and projections that
involve a number of risks and uncertainties which could cause actual events or
results to differ materially from those anticipated by the Trust and described
in the forward-looking information.  In addition, this MD&A may
contain forward-looking information attributed to third party industry
sources.  Undue reliance should not be placed on forward-looking
information, as there can be no assurance that the plans, intentions or
expectations upon which they are based will occur.  By its nature,
forward-looking information involves numerous assumptions, known and unknown
risks and uncertainties, both general and specific, that contribute to the
possibility that the predictions, forecasts, projections and other
forward-looking information will not occur.  Forward-looking
information in this MD&A includes, but is 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 an appropriate 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 financial derivative
instruments;
 ·
                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 midstream, NGL processing and
      marketing business;
 ·
                the
      growth opportunities associated with the midstream, NGL processing and
      marketing business; and
 ·
                the
      nature of contractual arrangements with third parties in respect of
      Provident's midstream, NGL processing and marketing
    business.
 
 Although
the Trust believes that the expectations reflected in the forward-looking
information 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 information.  Some of the risks
and other factors, some of which are beyond the Trust's control, which could
cause results to differ materially from those expressed in the forward-looking
information contained in this MD&A include, but are not limited
to:
  ·
                general
      economic and credit 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
      legislation taxing trust income;
 ·
                governmental
      regulation in North America of the oil and gas industry, including income
      tax and environmental regulation;
 ·
                fluctuation
      in foreign exchange or interest
rates;
 ·
                stock
      market volatility and market
valuations;
 ·
                the
      impact of environmental events;
 ·
                the
      need to obtain required approvals from regulatory
    authorities;
 ·
                unanticipated
      operating events which can reduce production or cause production to be
      shut-in or delayed;
 ·
                failure
      to realize the anticipated benefits of
  acquisitions;
 ·
                competition
      for, among other things, capital reserves, undeveloped lands and skilled
      personnel;
 ·
                failure
      to obtain industry partner and other third party consents and approvals,
      when required;
 ·
                risks
      associated with foreign ownership;
 ·
                third
      party performance of obligations under contractual arrangements;
      and
 ·
                the
      other factors set forth under "Business risks" in this
      MD&A.
 
 Readers
are cautioned that the foregoing list is not exhaustive of all possible risks
and uncertainties.  With respect to developing forward-looking
information contained in this MD&A, the Trust has made assumptions
regarding, among other things:
  
  ·
                future
      natural gas and crude oil prices;
 ·
                the
      ability of the Trust to obtain qualified staff and equipment in a timely
      and cost-efficient manner to meet
demand;
 ·
                the
      regulatory framework regarding royalties, taxes and environmental matters
      in which the Trust conducts its
business;
 ·
                the
      impact of increasing competition;
 ·
                the
      Trust's ability to obtain financing on acceptable
  terms;
 ·
                the
      general stability of the economic and political environment in which the
      Trust operates;
 ·
                the
      timely receipt of any required regulatory
  approvals;
 ·
                the
      ability of the operator of the projects which the Trust has an interest in
      to operate the field in a safe, efficient and effective
      manner;
 ·
                field
      production rates and decline rates;
 ·
                the
      ability to replace and expand oil and natural gas reserves through
      acquisition, development or
exploration;
 ·
                the
      timing and costs of pipeline, storage and facility construction and
      expansion and the ability of the Trust to secure adequate product
      transportation;
 ·
                currency,
      exchange and interest rates; and
 ·
                the
      ability of the Trust to successfully market its oil and natural gas
      products.
 
 Readers
are cautioned that the foregoing list is not exhaustive of all factors and
assumptions which have been used.  Forward-looking information
contained in this MD&A is made as of the date hereof and the Trust
undertakes no obligation to update publicly or revise any forward-looking
information, whether as a result of new information, future events or otherwise,
unless required by applicable securities laws. The forward-looking information
contained in this MD&A is expressly qualified by this cautionary
statement.
 
 
 Additional
information
 
 Additional
information concerning Provident can be accessed under Provident’s public
filings at www.sedar.com and
www.sec.gov/edgar.shtml,
as well as on Provident’s website at www.providentenergy.com.
 
 
 Selected
annual financial measures
  ($
      000s except per unit data)
                  
                  2009
                  
                  
                  2008
                  
                  
                  2007Revenue
      from continuing operations (net of royalties andfinancial
      derivative instruments)
                  
                  $
                  1,711,483
                  
                  
                  $
                  3,239,163
                  
                  
                  $
                  2,038,515Net
      (loss) income
                  
                  
                  (89,020
                  )
                  
                  
                  157,392
                  
                  
                  
                  30,434Per
      unit - basic and diluted
                  
                  
                  (0.34
                  )
                  
                  
                  0.62
                  
                  
                  
                  0.13Total
      assets
                  
                  
                  2,548,015
                  
                  
                  
                  3,074,069
                  
                  
                  
                  5,758,792Long-term
      financial liabilities from continuing operations (1)
                  
                  
                  682,625
                  
                  
                  
                  867,232
                  
                  
                  
                  1,382,921Declared
      distributions per unit.
                  
                  $
                  0.75
                  
                  
                  $
                  1.38
                  
                  
                  $
                  1.44(1)
      Includes long-term debt, asset retirement obligation, long-term financial
      derivative instruments and other long-term liabilities.
 
 
 Quarterly table
  
 Segmented
      information by quarter($
      000s except for per unit and operating amounts)
                  
                  
                  
                  
                  
                  
                  
                  2009First
                  
                  
                  Second
                  
                  
                  Third
                  
                  
                  Fourth
                  
                  
                  AnnualQuarter
                  
                  
                  Quarter
                  
                  
                  Quarter
                  
                  
                  Quarter
                  
                  
                  TotalFinancial
      - consolidatedRevenue
                  
                  $
                  470,769
                  
                  
                  $
                  305,923
                  
                  
                  $
                  465,432
                  
                  
                  $
                  469,359
                  
                  
                  $
                  1,711,483Funds
      flow from continuing operations
                  
                  $
                  84,281
                  
                  
                  $
                  48,516
                  
                  
                  $
                  54,869
                  
                  
                  $
                  76,340
                  
                  
                  $
                  264,006Funds
      flow from continuing operations per unit - basic and
    diluted
                  
                  $
                  0.32
                  
                  
                  $
                  0.19
                  
                  
                  
                  0.21
                  
                  
                  
                  0.29
                  
                  
                  $
                  1.01Net
      (loss) income
                  
                  $
                  (40,284
                  )
                  
                  $
                  (80,061
                  )
                  
                  $
                  51,663
                  
                  
                  $
                  (20,338
                  )
                  
                  $
                  (89,020
                  )Net
      (loss) income per unit - basic and diluted
                  
                  $
                  (0.16
                  )
                  
                  $
                  (0.31
                  )
                  
                  $
                  0.20
                  
                  
                  $
                  (0.08
                  )
                  
                  $
                  (0.34
                  )Unitholder
      distributions
                  
                  $
                  54,511
                  
                  
                  $
                  47,012
                  
                  
                  $
                  47,238
                  
                  
                  $
                  47,456
                  
                  
                  $
                  196,217Distributions
      per unit
                  
                  $
                  0.21
                  
                  
                  $
                  0.18
                  
                  
                  $
                  0.18
                  
                  
                  $
                  0.18
                  
                  
                  $
                  0.75Provident
      UpstreamCash
      revenue
                  
                  $
                  72,242
                  
                  
                  $
                  78,883
                  
                  
                  $
                  69,208
                  
                  
                  $
                  57,263
                  
                  
                  $
                  277,596Earnings
      before interest, DD&A, taxes and other non-cash items
                  
                  $
                  25,119
                  
                  
                  $
                  33,114
                  
                  
                  $
                  30,344
                  
                  
                  $
                  20,416
                  
                  
                  $
                  108,993Funds
      flow from operations
                  
                  $
                  22,827
                  
                  
                  $
                  30,022
                  
                  
                  $
                  28,425
                  
                  
                  $
                  20,882
                  
                  
                  $
                  102,156Net
      loss
                  
                  $
                  (38,154
                  )
                  
                  $
                  (29,885
                  )
                  
                  $
                  (21,879
                  )
                  
                  $
                  (20,649
                  )
                  
                  $
                  (110,567
                  )Provident
      MidstreamCash
      revenue
                  
                  $
                  487,820
                  
                  
                  $
                  314,537
                  
                  
                  $
                  309,215
                  
                  
                  $
                  452,176
                  
                  
                  $
                  1,563,748Earnings
      before interest, DD&A, taxes and other non-cash items
                  
                  $
                  69,927
                  
                  
                  $
                  24,416
                  
                  
                  $
                  27,119
                  
                  
                  $
                  60,855
                  
                  
                  $
                  182,317Funds
      flow from operations
                  
                  $
                  61,454
                  
                  
                  $
                  18,494
                  
                  
                  $
                  26,444
                  
                  
                  $
                  55,458
                  
                  
                  $
                  161,850Net
      (loss) income
                  
                  $
                  (2,130
                  )
                  
                  $
                  (50,176
                  )
                  
                  $
                  73,542
                  
                  
                  $
                  311
                  
                  
                  $
                  21,547OperatingOil
      and gas productionCrude
      oil (bpd)
                  
                  
                  10,710
                  
                  
                  
                  10,035
                  
                  
                  
                  9,276
                  
                  
                  
                  5,533
                  
                  
                  
                  8,875Natural
      gas liquids (bpd)
                  
                  
                  1,138
                  
                  
                  
                  1,105
                  
                  
                  
                  1,169
                  
                  
                  
                  1,072
                  
                  
                  
                  1,121Natural
      gas (mcfd)
                  
                  
                  76,260
                  
                  
                  
                  75,735
                  
                  
                  
                  65,525
                  
                  
                  
                  60,992
                  
                  
                  
                  69,575Oil
      equivalent (boed)
                  
                  
                  24,558
                  
                  
                  
                  23,763
                  
                  
                  
                  21,366
                  
                  
                  
                  16,770
                  
                  
                  
                  21,592Average
      selling price net of transportation expense (Cdn$)Crude
      oil per bbl
                  
                  $
                  36.23
                  
                  
                  $
                  59.03
                  
                  
                  $
                  62.06
                  
                  
                  $
                  66.03
                  
                  
                  $
                  54.15(before
      realized financial derivative instruments)Crude
      oil per bbl
                  
                  $
                  42.31
                  
                  
                  $
                  60.61
                  
                  
                  $
                  62.56
                  
                  
                  $
                  66.67
                  
                  
                  $
                  56.63(including
      realized financial derivative instruments)Natural
      gas liquids per barrel
                  
                  $
                  41.13
                  
                  
                  $
                  38.14
                  
                  
                  $
                  39.76
                  
                  
                  $
                  59.25
                  
                  
                  $
                  44.40Natural
      gas per mcf
                  
                  $
                  4.75
                  
                  
                  $
                  3.40
                  
                  
                  $
                  2.90
                  
                  
                  $
                  4.36
                  
                  
                  $
                  3.86(before
      realized financial derivative instruments)Natural
      gas per mcf
                  
                  $
                  5.26
                  
                  
                  $
                  3.62
                  
                  
                  $
                  3.28
                  
                  
                  $
                  4.54
                  
                  
                  $
                  4.19(including
      realized financial derivative instruments)Provident
      MidstreamProvident
      Midstream NGL sales volumes (bpd)
                  
                  
                  141,669
                  
                  
                  
                  102,799
                  
                  
                  
                  98,229
                  
                  
                  
                  111,912
                  
                  
                  
                  113,528
   
 
 Quarterly
table
 
 Segmented
      information by quarter($
      000s except for per unit and operating amounts)
                  
                  
                  
                  
                  
                  
                  
                  2008First
                  
                  
                  Second
                  
                  
                  Third
                  
                  
                  Fourth
                  
                  
                  AnnualQuarter
                  
                  
                  Quarter
                  
                  
                  Quarter
                  
                  
                  Quarter
                  
                  
                  TotalFinancial
      - consolidatedRevenue
      (continuing operations)
                  
                  $
                  702,215
                  
                  
                  $
                  420,220
                  
                  
                  $
                  1,097,408
                  
                  
                  $
                  1,019,320
                  
                  
                  $
                  3,239,163Funds
      flow from continuing operations
                  
                  $
                  130,394
                  
                  
                  $
                  165,470
                  
                  
                  $
                  139,979
                  
                  
                  $
                  81,779
                  
                  
                  $
                  517,622Funds
      flow from continuing operations per unit - basic
                  
                  $
                  0.52
                  
                  
                  $
                  0.65
                  
                  
                  $
                  0.55
                  
                  
                  $
                  0.32
                  
                  
                  $
                  2.03Funds
      flow from continuing operations per unit - diluted
                  
                  $
                  0.52
                  
                  
                  $
                  0.65
                  
                  
                  $
                  0.51
                  
                  
                  $
                  0.32
                  
                  
                  $
                  2.03Net
      income (loss)
                  
                  $
                  33,616
                  
                  
                  $
                  (184,081
                  )
                  
                  $
                  351,105
                  
                  
                  $
                  (43,248
                  )
                  
                  $
                  157,392Net
      income (loss) per unit - basic
                  
                  $
                  0.13
                  
                  
                  $
                  (0.72
                  )
                  
                  $
                  1.37
                  
                  
                  $
                  (0.17
                  )
                  
                  $
                  0.62Net
      income (loss) per unit - diluted
                  
                  $
                  0.13
                  
                  
                  $
                  (0.72
                  )
                  
                  $
                  1.29
                  
                  
                  $
                  (0.17
                  )
                  
                  $
                  0.62Unitholder
      distributions
                  
                  $
                  91,117
                  
                  
                  $
                  91,662
                  
                  
                  $
                  92,188
                  
                  
                  $
                  77,324
                  
                  
                  $
                  352,291Distributions
      per unit
                  
                  $
                  0.36
                  
                  
                  $
                  0.36
                  
                  
                  $
                  0.36
                  
                  
                  $
                  0.30
                  
                  
                  $
                  1.38Oil
      and gas production (continuing operations)Cash
      revenue
                  
                  $
                  122,815
                  
                  
                  $
                  164,442
                  
                  
                  $
                  158,400
                  
                  
                  $
                  101,437
                  
                  
                  $
                  547,094Earnings
      before interest, DD&A, taxes and other non-cash items
                  
                  $
                  75,348
                  
                  
                  $
                  117,132
                  
                  
                  $
                  111,256
                  
                  
                  $
                  49,757
                  
                  
                  $
                  353,493Funds
      flow from operations
                  
                  $
                  71,142
                  
                  
                  $
                  112,869
                  
                  
                  $
                  107,442
                  
                  
                  $
                  47,187
                  
                  
                  $
                  338,640Net
      income (loss)
                  
                  $
                  9,591
                  
                  
                  $
                  28,935
                  
                  
                  $
                  76,881
                  
                  
                  $
                  (421,457
                  )
                  
                  $
                  (306,050
                  )Provident
      MidstreamCash
      revenue
                  
                  $
                  641,673
                  
                  
                  $
                  662,315
                  
                  
                  $
                  652,753
                  
                  
                  $
                  513,860
                  
                  
                  $
                  2,470,601Earnings
      before interest, DD&A, taxes and other non-cash items
                  
                  $
                  75,987
                  
                  
                  $
                  61,769
                  
                  
                  $
                  37,339
                  
                  
                  $
                  37,666
                  
                  
                  $
                  212,761Funds
      flow from operations
                  
                  $
                  59,252
                  
                  
                  $
                  52,601
                  
                  
                  $
                  32,537
                  
                  
                  $
                  34,592
                  
                  
                  $
                  178,982Net
      income (loss)
                  
                  $
                  15,516
                  
                  
                  $
                  (290,230
                  )
                  
                  $
                  232,966
                  
                  
                  $
                  359,166
                  
                  
                  $
                  317,418OperatingOil
      and gas production (continuing operations)Crude
      oil (bpd)
                  
                  
                  12,287
                  
                  
                  
                  12,494
                  
                  
                  
                  12,805
                  
                  
                  
                  12,307
                  
                  
                  
                  12,473Natural
      gas liquids (bpd)
                  
                  
                  1,307
                  
                  
                  
                  1,178
                  
                  
                  
                  1,195
                  
                  
                  
                  1,134
                  
                  
                  
                  1,203Natural
      gas (mcfd)
                  
                  
                  83,970
                  
                  
                  
                  86,130
                  
                  
                  
                  85,628
                  
                  
                  
                  80,450
                  
                  
                  
                  84,039Oil
      equivalent (boed)
                  
                  
                  27,589
                  
                  
                  
                  28,027
                  
                  
                  
                  28,271
                  
                  
                  
                  26,849
                  
                  
                  
                  27,683Average
      selling price net of transportation expense(continuing
      operations) (Cdn$)Crude
      oil per bbl
                  
                  $
                  75.06
                  
                  
                  $
                  105.13
                  
                  
                  $
                  102.66
                  
                  
                  $
                  47.33
                  
                  
                  $
                  82.79(before
      realized financial derivative instruments)Crude
      oil per bbl
                  
                  $
                  71.54
                  
                  
                  $
                  98.68
                  
                  
                  $
                  97.61
                  
                  
                  $
                  52.71
                  
                  
                  $
                  80.36(including
      realized financial derivative instruments)Natural
      gas liquids per barrel
                  
                  $
                  72.85
                  
                  
                  $
                  94.59
                  
                  
                  $
                  91.72
                  
                  
                  $
                  47.64
                  
                  
                  $
                  76.88Natural
      gas per mcf
                  
                  $
                  7.61
                  
                  
                  $
                  9.98
                  
                  
                  $
                  8.60
                  
                  
                  $
                  6.63
                  
                  
                  $
                  8.23(before
      realized financial derivative instruments)Natural
      gas per mcf
                  
                  $
                  7.74
                  
                  
                  $
                  9.73
                  
                  
                  $
                  8.45
                  
                  
                  $
                  6.92
                  
                  
                  $
                  8.23(including
      realized financial derivative instruments)Provident
      MidstreamProvident
      Midstream NGL sales volumes (bpd)
                  
                  
                  136,320
                  
                  
                  
                  110,826
                  
                  
                  
                  111,313
                  
                  
                  
                  120,222
                  
                  
                  
                  119,649
 
 
 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, 2009, 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.
 
 The
effectiveness of the Trust’s internal control over financial reporting as of
December 31, 2009, has been audited by PricewaterhouseCoopers LLP, independent
auditors, as stated in their report which appears herein.
  
  “Signed”
                
                “Signed”Thomas W.
    Buchanan
                
                Mark N.
  WalkerChief Executive
      Officer
                
                Chief Financial
      Officer
  Calgary,
Alberta
 March 11,
2010
   
 
 
 MANAGEMENT’S
RESPONSIBILITY FOR FINANCIAL STATEMENTS
 
 The
management of Provident is responsible for the information included in this
Annual Report. The financial statements have been prepared in accordance with
accounting principles generally accepted in Canada and in accordance with
accounting policies detailed in the notes to the financial
statements.  Where necessary, the statements include amounts based on
management’s informed judgments and estimates.  Financial information
in the Annual Report is consistent with that presented in the financial
statements.
 
 PricewaterhouseCoopers
LLP, Chartered Accountants, appointed by the unitholders, have audited the
financial statements and conducted a review of internal accounting policies and
procedures to the extent required by generally accepted auditing standards, and
performed such tests as they deemed necessary to enable them to express an
opinion on the financial statements.
 
 The Board
of Directors, through its Audit Committee, is responsible for ensuring that
management fulfills its responsibility for financial reporting and internal
control.  The Audit Committee is composed of three independent
directors.  The Audit Committee reviews the financial content of the
Annual Report and reports its findings to the Board of Directors for its
consideration in approving the financial statements.
 
 “Signed”
                  
                  “Signed”Thomas W.
    Buchanan
                  
                  Mark N.
  WalkerChief Executive
      Officer
                  
                  Chief Financial
      Officer
 Calgary,
Alberta
 March 11,
2010
   
 
 
  To the
Unitholders of Provident Energy Trust
 
 We have
completed integrated audits of Provident Energy Trust’s (the “Trust”) 2009 and
2008 consolidated financial statements and of its internal control over
financial reporting as at December 31, 2009.  Our opinions, based on
our audits, are presented below.
 
  Consolidated
Financial statements
  We have
audited the accompanying consolidated balance sheets of Provident Energy Trust
as at December 31, 2009 and December 31, 2008, and the related consolidated
statements of
operations and accumulated income, comprehensive and accumulated other
comprehensive income and cash flows for each of the years then
ended.  These consolidated financial statements are the responsibility
of the Trust’s management. Our responsibility is to express an opinion on these
consolidated financial statements based on our audits.
 
 We
conducted our audits of the Trust’s consolidated financial statements in
accordance with Canadian generally accepted auditing standards and the standards
of the Public Company Accounting Oversight Board (United States). 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. We believe that our
audits provide a reasonable basis for our opinion.
 
 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,
2009 and December 31, 2008 and the results of its operations and its cash flows
for each of the years then ended in accordance with Canadian generally accepted
accounting principles.
 
 Internal
control over financial reporting
  We have
also audited Provident Energy Trust’s internal control over financial reporting
as at December 31, 2009, 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
included in the accompanying Management’s Report on Internal Control Over
Financial Reporting.  Our responsibility is to express an opinion on
the Trust’s internal control over financial reporting based on our
audit.
  
 “PricewaterhouseCoopers” refers to
PricewaterhouseCoopers LLP, an Ontario limited liability partnership, or, as the
context requires, the PricewaterhouseCoopers global network or other member
firms of the network, each of which is a separate and independent legal
entity.
  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, assessing the risk that a material
weakness exists, testing and evaluating the design and operating effectiveness
of internal control based on the assessed risk, and performing such other
procedures as we consider necessary in the circumstances.  We believe
that our audit provides a reasonable basis for our opinion.
 
 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, the Trust maintained, in all material respects, effective internal
control over financial reporting as at December 31, 2009based on criteria
established in Internal Control — Integrated Framework issued by the
COSO.
 
 
 
 
 
 
 Chartered
Accountants
 March 11,
2010




PROVIDENT
      ENERGY TRUSTCONSOLIDATED
      BALANCE SHEETSCanadian
      dollars (000s)As
      at
                    
                    
                    As
      atDecember
      31,
                    
                    
                    December
      31,2009
                    
                    
                    2008AssetsCurrent
      assetsCash
      and cash equivalents
                    
                    $
                    7,187
                    
                    
                    $
                    4,629Accounts
      receivable
                    
                    
                    216,786
                    
                    
                    
                    244,485Petroleum
      product inventory
                    
                    
                    37,261
                    
                    
                    
                    46,160Prepaid
      expenses and other current assets
                    
                    
                    4,803
                    
                    
                    
                    7,886Financial
      derivative instruments (note 14)
                    
                    
                    5,314
                    
                    
                    
                    16,708271,351
                    
                    
                    
                    319,868Investments
      and other long term assets
                    
                    
                    18,733
                    
                    
                    
                    14,218Long-term
      financial derivative instruments (note 14)
                    
                    
                    -
                    
                    
                    
                    735Property,
      plant and equipment (note 6)
                    
                    
                    2,025,044
                    
                    
                    
                    2,480,503Intangible
      assets (note 7)
                    
                    
                    132,478
                    
                    
                    
                    158,336Goodwill
      (note 8)
                    
                    
                    100,409
                    
                    
                    
                    100,409$
                    2,548,015
                    
                    
                    $
                    3,074,069LiabilitiesCurrent
      liabilitiesAccounts
      payable and accrued liabilities
                    
                    $
                    221,417
                    
                    
                    $
                    244,031Cash
      distributions payable
                    
                    
                    13,468
                    
                    
                    
                    20,088Current
      portion of convertible debentures (note 9)
                    
                    
                    -
                    
                    
                    
                    24,871Financial
      derivative instruments (note 14)
                    
                    
                    86,441
                    
                    
                    
                    13,693321,326
                    
                    
                    
                    302,683Long-term
      debt - revolving term credit facility (note 9)
                    
                    
                    264,776
                    
                    
                    
                    504,685Long-term
      debt - convertible debentures (note 9)
                    
                    
                    240,486
                    
                    
                    
                    236,123Asset
      retirement obligation (note 10)
                    
                    
                    61,464
                    
                    
                    
                    59,432Long-term
      financial derivative instruments (note 14)
                    
                    
                    103,403
                    
                    
                    
                    58,420Other
      long-term liabilities (note 12)
                    
                    
                    12,496
                    
                    
                    
                    8,572Future
      income taxes (note 13)
                    
                    
                    162,665
                    
                    
                    
                    267,807Unitholders’
      equityUnitholders’
      contributions (note 11)
                    
                    
                    2,834,177
                    
                    
                    
                    2,806,071Convertible
      debentures equity component
                    
                    
                    15,940
                    
                    
                    
                    17,198Contributed
      surplus (note 11)
                    
                    
                    2,953
                    
                    
                    
                    1,695Accumulated
      other comprehensive loss
                    
                    
                    -
                    
                    
                    
                    (2,183
                    )Accumulated
      income
                    
                    
                    337,014
                    
                    
                    
                    426,034Accumulated
      cash distributions
                    
                    
                    (1,808,685
                    )
                    
                    
                    (1,612,468
                    )1,381,399
                    
                    
                    
                    1,636,347$
                    2,548,015
                    
                    
                    $
                    3,074,069*
      Note: For rounding differences, please add/subtract from AP to get to
      balance.
 The
accompanying notes to the consolidated financial statements are an integral part
of these statements.
 
 On behalf
of the Board of Directors:
 
 “Signed”
                  “Signed”M.H. (Mike)
      Shaikh, FCA
                  Thomas W.
      Buchanan, FCADirector
                  Director
 
 
 
 PROVIDENT
      ENERGY TRUSTCONSOLIDATED
      STATEMENT OF OPERATIONS AND ACCUMULATED INCOMECanadian
      dollars (000s except per unit amounts)Year
      endedDecember
      31,2009
                  
                  
                  2008RevenueRevenue
                  
                  $
                  1,891,983
                  
                  
                  $
                  3,147,714Realized
      loss on financial derivative instruments
                  
                  
                  (50,639
                  )
                  
                  
                  (130,019
                  )Unrealized
      (loss) gain on financial derivative instruments
                  
                  
                  (129,861
                  )
                  
                  
                  221,4681,711,483
                  
                  
                  
                  3,239,163ExpensesCost
      of goods sold
                  
                  
                  1,305,191
                  
                  
                  
                  2,206,427Production,
      operating and maintenance
                  
                  
                  133,969
                  
                  
                  
                  153,111Transportation
                  
                  
                  35,467
                  
                  
                  
                  37,120Depletion,
      depreciation and accretion
                  
                  
                  312,709
                  
                  
                  
                  343,315Goodwill
      impairment (note 8)
                  
                  
                  -
                  
                  
                  
                  416,890General
      and administrative (note 12)
                  
                  
                  68,348
                  
                  
                  
                  63,281Strategic
      review and restructuring (note 16)
                  
                  
                  12,257
                  
                  
                  
                  3,632Interest
      on bank debt
                  
                  
                  9,860
                  
                  
                  
                  36,088Interest
      and accretion on convertible debentures
                  
                  
                  21,957
                  
                  
                  
                  19,944Foreign
      exchange loss (gain) and other
                  
                  
                  5,289
                  
                  
                  
                  (20,828
                  )1,905,047
                  
                  
                  
                  3,258,980Loss
      from continuing operations before taxes
                  
                  
                  (193,564
                  )
                  
                  
                  (19,817
                  )Capital
      tax expense
                  
                  
                  2,313
                  
                  
                  
                  3,109Current
      tax expense (recovery)
                  
                  
                  237
                  
                  
                  
                  (4,529
                  )Future
      income tax recovery (note 13)
                  
                  
                  (107,094
                  )
                  
                  
                  (29,765
                  )(104,544
                  )
                  
                  
                  (31,185
                  )Net
      (loss) income from continuing operations
                  
                  
                  (89,020
                  )
                  
                  
                  11,368Net
      income from discontinued operations (note 17)
                  
                  
                  -
                  
                  
                  
                  146,024Net
      (loss) income for the year
                  
                  
                  (89,020
                  )
                  
                  
                  157,392Accumulated
      income, beginning of year
                  
                  $
                  426,034
                  
                  
                  $
                  268,642Accumulated
      income, end of year
                  
                  $
                  337,014
                  
                  
                  $
                  426,034Net
      (loss) income from continuing operations per unit-
      basic and diluted
                  
                  $
                  (0.34
                  )
                  
                  $
                  0.04Net
      (loss) income per unit-
      basic and diluted
                  
                  $
                  (0.34
                  )
                  
                  $
                  0.62
 
 The
accompanying notes to the consolidated financial statements are an integral part
of these statements.
  
 
 PROVIDENT
      ENERGY TRUSTCONSOLIDATED
      STATEMENT OF CASH FLOWSCanadian
      dollars (000s)Year
      endedDecember
      31,2009
                  
                  
                  2008Cash
      provided by operating activitiesNet
      (loss) income for the year from continuing operations
                  
                  $
                  (89,020
                  )
                  
                  $
                  11,368Add
      (deduct) non-cash items:Depletion,
      depreciation and accretion
                  
                  
                  312,709
                  
                  
                  
                  343,315Goodwill
      impairment (note 8)
                  
                  
                  -
                  
                  
                  
                  416,890Non-cash
      interest expense and other
                  
                  
                  4,952
                  
                  
                  
                  5,291Non-cash
      unit based compensation expense (recovery) (note 12)
                  
                  
                  6,326
                  
                  
                  
                  (4,117
                  )Unrealized
      loss (gain) on financial derivative instruments
                  
                  
                  129,861
                  
                  
                  
                  (221,468
                  )Unrealized
      foreign exchange loss (gain) and other
                  
                  
                  4,161
                  
                  
                  
                  (3,892
                  )Loss
      on sale of investment
                  
                  
                  2,111
                  
                  
                  
                  -Future
      income tax recovery
                  
                  
                  (107,094
                  )
                  
                  
                  (29,765
                  )264,006
                  
                  
                  
                  517,622Site
      restoration expenditures
                  
                  
                  (5,399
                  )
                  
                  
                  (6,381
                  )Change
      in non-cash operating working capital
                  
                  
                  45,641
                  
                  
                  
                  52,684Cash
      provided by operating activities from discontinued
    operations
                  
                  
                  -
                  
                  
                  
                  110,501304,248
                  
                  
                  
                  674,426Cash
      used for financing activitiesDecrease
      in long-term debt
                  
                  
                  (265,245
                  )
                  
                  
                  (440,244
                  )Distributions
      to unitholders
                  
                  
                  (196,217
                  )
                  
                  
                  (352,291
                  )Issue
      of trust units
                  
                  
                  28,106
                  
                  
                  
                  55,510Change
      in non-cash financing working capital
                  
                  
                  (6,620
                  )
                  
                  
                  (5,028
                  )Financing
      activities from discontinued operations
                  
                  
                  -
                  
                  
                  
                  (47,511
                  )(439,976
                  )
                  
                  
                  (789,564
                  )Cash
      provided by investing activitiesCapital
      expenditures
                  
                  
                  (127,369
                  )
                  
                  
                  (246,947
                  )Acquisitions
      (note 4)
                  
                  
                  (18,833
                  )
                  
                  
                  (25,843
                  )Proceeds
      on sale of assets (note 5)
                  
                  
                  305,720
                  
                  
                  
                  1,662Proceeds
      on sale of discontinued operations, net of tax
                  
                  
                  -
                  
                  
                  
                  457,906Decrease
      (increase) in investments
                  
                  
                  625
                  
                  
                  
                  (792
                  )Change
      in non-cash investing working capital
                  
                  
                  (21,857
                  )
                  
                  
                  (3,229
                  )Investing
      activities from discontinued operations
                  
                  
                  -
                  
                  
                  
                  (69,810
                  )138,286
                  
                  
                  
                  112,947Increase
      (decrease) in cash and cash equivalents
                  
                  
                  2,558
                  
                  
                  
                  (2,191
                  )Cash
      and cash equivalents, beginning of year
                  
                  
                  4,629
                  
                  
                  
                  6,820Cash
      and cash equivalents, end of year
                  
                  $
                  7,187
                  
                  
                  $
                  4,629Supplemental
      disclosure of cash flow informationCash
      interest paid including debenture interest
                  
                  $
                  27,826
                  
                  
                  $
                  63,490Cash
      taxes paid
                  
                  $
                  3,199
                  
                  
                  $
                  210,132
 
 The
accompanying notes to the consolidated financial statements are an integral part
of these statements.
 
  
 
 PROVIDENT
      ENERGY TRUSTCONSOLIDATED
      STATEMENT OF COMPREHENSIVE INCOMEAND
      ACCUMULATED OTHER COMPREHENSIVE INCOMECanadian
      dollars (000s)Year
      endedDecember
      31,2009
                  
                  
                  2008Net
      (loss) income
                  
                  $
                  (89,020
                  )
                  
                  $
                  157,392Other
      comprehensive income, net of taxesForeign
      currency translation adjustments
                  
                  
                  -
                  
                  
                  
                  10,315Reclassification
      adjustment for foreign currency lossesincluded
      in net income
                  
                  
                  -
                  
                  
                  
                  57,062Reclassification
      adjustment of loss on available-for-saleinvestment
      included in net income
                  
                  
                  2,111
                  
                  
                  
                  -Unrealized
      gain (loss) on available-for-sale investments (net of
    taxes)
                  
                  
                  72
                  
                  
                  
                  (372
                  )2,183
                  
                  
                  
                  67,005Comprehensive
      (loss) income
                  
                  $
                  (86,837
                  )
                  
                  $
                  224,397Accumulated
      other comprehensive loss, beginning of year
                  
                  
                  (2,183
                  )
                  
                  
                  (69,188
                  )Other
      comprehensive income
                  
                  
                  2,183
                  
                  
                  
                  67,005Accumulated
      other comprehensive loss, end of year
                  
                  $
                  -
                  
                  
                  $
                  (2,183
                  )Accumulated
      income, end of year
                  
                  
                  337,014
                  
                  
                  
                  426,034Accumulated
      cash distributions, end of year
                  
                  
                  (1,808,685
                  )
                  
                  
                  (1,612,468
                  )Retained
      earnings (deficit), end of year
                  
                  
                  (1,471,671
                  )
                  
                  
                  (1,186,434
                  )Accumulated
      other comprehensive loss, end of year
                  
                  
                  -
                  
                  
                  
                  (2,183
                  )Total
      retained earnings (deficit) and accumulated othercomprehensive
      loss, end of year
                  
                  $
                  (1,471,671
                  )
                  
                  $
                  (1,188,617
                  )
 
 The
accompanying notes to the consolidated financial statements are an integral part
of these statements.
 
 
 
 Notes to
the Consolidated
 Financial
Statements
 
 (Tabular
amounts in Cdn $ 000’s, except unit and per unit amounts, and as
noted)
 
 
 December
31, 2009
 
 
 1.
                Structure
      of the Trust
 
 Provident
Energy Trust (the “Trust” or “Provident”) 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 directly and
indirectly owned subsidiaries of the Trust. Cash flow is paid to the Trust by
way of royalty payments, interest payments, principal debt repayments and
dividends or partnership distributions.  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, including
the consolidated accounts of all wholly and partially owned subsidiaries, and
are presented in accordance with Canadian generally accepted accounting
principles.  Investments subject to significant influence are
accounted for using the equity method.  Certain comparative figures
have been reclassified to conform to the current year
presentation.
 
 ii)
                Financial
      instruments
 
 All
financial instruments, including derivatives, are recognized on the Trust’s
Consolidated Balance Sheet.  Derivatives are measured at fair value
with unrealized gains and losses reported in net income.  Investments
in equity instruments that are not quoted in an active market are recorded at
cost.  Investments in equity instruments that are quoted in an active
market are measured at fair value, with reference to published price quotations,
and unrealized gains and losses are reported in AOCI.  The Trust’s
other financial instruments (accounts receivable, accounts payable and accrued
liabilities, cash distributions payable, and long-term debt) are measured at
amortized cost using the effective interest rate method.  Transaction
costs are included with the associated financial instruments and amortized
accordingly.
 
 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. Costs associated with the acquisition and
development of oil and natural gas reserves are capitalized and accumulated in
one cost centre as all of the oil and natural gas assets are in
Canada.  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 15 months to 15
years.  Capital assets related to pipelines and office equipment are
carried at cost and depreciated using the straight-line method over their
economic lives.
 
 b)
                Impairment
 
 Oil and
natural gas assets accounted for using the full cost method are subject to a
ceiling test.  The ceiling test calculation is performed by comparing
the carrying value of the assets to the sum of the undiscounted proved reserve
cash flows using future price estimates.  If the carrying value is not
recoverable, the assets are written down to their fair value.  Fair
value is determined by the future cash flows from the proved plus probable
reserves discounted at the Trust’s risk free interest rate.   Any
excess carrying value of the assets on the balance sheet above fair value would
be recorded in depletion, depreciation and accretion expense as a permanent
impairment.
 
 For
Midstream property, plant and equipment, and intangible assets, an impairment
loss is recognized when the carrying amount exceeds the fair
value.
 
 v)
                Joint
      venture
 
 Provident
conducts many of its activities through joint ventures and the accounts reflect
only Provident’s proportionate interest in such
activities.
 
 vi)
                Inventory
 
 Inventories
of products are valued at the lower of average cost and net realizable value
based on market prices.
 
 vii)
                Goodwill
 
 Goodwill,
which represents the excess of cost of an acquired enterprise over the net of
the amounts assigned to assets acquired and liabilities assumed, is assessed at
least annually for impairment.  To assess impairment, the fair value
of the reporting unit is determined and compared to the book value of the
reporting unit.  If the fair value is less than the book value, then a
second test is performed to determine the amount of the
impairment.  The amount of the impairment is determined by deducting
the fair value of the reporting unit’s assets and liabilities from the fair
value of the reporting unit to determine the implied fair value of goodwill and
comparing that amount to the book value of the reporting unit’s
goodwill.  Any
  
 
 excess of
the book value of goodwill over the implied fair value of goodwill is the
impaired amount.  Goodwill is not
amortized.
 
 viii)
                Asset retirement
      obligation
 
 Under the
asset retirement obligation (“ARO”) standard the fair value of a liability for
an ARO is recorded in the period where a reasonable estimate of the fair value
can be determined.  When the liability is recorded, the carrying
amount of the related asset is increased by the same amount of the
liability.  The asset recorded is depleted over the useful life of the
asset.  Additions to asset retirement obligations due to the passage
of time are recorded as accretion expense. Actual expenditures incurred are
charged against the obligation.
 
 ix)
                Unit based
      compensation
 
 The Trust
uses the fair value method of valuing compensation expense associated with the
Trust’s unit option plan.  Under the fair value method the amount to
be recognized as expense is determined at the time the options are issued and is
recognized in earnings over the vesting period of the options with a
corresponding increase in contributed surplus.
 
 The Trust
has established other unit based compensation plans whereby notional units are
granted to employees. The fair value of these notional units is estimated and
recorded as non-cash unit based compensation (a component of general and
administrative expenses).  A portion relating to operational employees
at field and plant locations is allocated to operating expense.  The
offsetting amount is recorded as accrued liabilities or other long-term
liabilities. A realization of the expense and a resulting reduction in cash
provided by operating activities occurs when a cash payment is
made.
 
 x)
                Trust unit
      calculations
 
 The Trust
applies the treasury stock method to determine the dilutive effect of trust unit
rights and trust unit options.  Under the treasury stock method,
outstanding and exercisable instruments that will have a dilutive effect are
included in per unit - diluted calculations, ordered from most dilutive to least
dilutive.
 
 The
dilutive effect of convertible debentures is determined using the "if-converted"
method whereby the outstanding debentures at the end of the period are assumed
to have been converted at the beginning of the period or at the time of issue if
issued during the year.  Amounts charged to income or loss relating to
the outstanding debentures are added back to net income for the diluted
calculation. The units issued upon conversion are included in the denominator of
per unit - basic calculations from the date of issue.
 
 xi)
                Income
    taxes
 
 Provident
follows the liability method for calculating income
taxes.  Differences between the amounts reported in the financial
statements of the corporate subsidiaries and their respective tax bases are
applied to tax rates in effect to calculate the future tax
liability.  The effect of any change in income tax rates is recognized
in the current period income.
 
 The Trust
is a taxable entity under the Income Tax Act (Canada) and is currently taxable
only on income that is not distributed or distributable to the
unitholders.  As the Trust distributes all of its taxable income to
the unitholders and meets the requirements of the Income Tax Act (Canada)
applicable to the Trust, no provision for current income taxes has been made in
the Trust.
 
 In 2007,
the Canadian government enacted Bill C-52, Budget Implementation Act
2007.  This bill contains legislation to tax publicly traded trusts,
commencing in 2011.  As a result of this legislation, the Trust
records the future income tax effect of the temporary differences on its flow
through entities that are expected to reverse subsequent to
2010.
 
  
 xi)
                  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.
 
 Revenues
associated with the services provided where Provident acts as agent are recorded
on a net basis when the services are provided.  Revenues associated
with the sale of natural gas liquids storage services are recognized when the
services are provided.
 
 xiii)
                Foreign currency
      translation
 
 The
accounts of self-sustaining foreign operations are translated using the current
rate method, whereby assets and liabilities are translated at period-end
exchange rates, while revenue and expenses are translated using average rates
for the period.  Translation gains and losses related to
self-sustaining operations are deferred and included as a component of
accumulated other comprehensive income.  A proportionate amount of the
gain or loss is recognized in net income when there has been a reduction in the
net investment.
 
 The
accounts of integrated foreign operations are translated using the temporal
method, under which monetary assets and liabilities are translated at the
period-end exchange rate, other assets and liabilities at the historical rates,
and revenues and expenses at the rates for the period, except depreciation,
depletion and accretion which is translated on the same basis as the related
assets.  Translation gains and losses are included in income in the
period in which they arise.
 
 xiv)
                Use of
      estimates
 
 The
preparation of financial statements requires management to make estimates based
on currently available information.  Actual results could differ from
those estimated.  In particular, management makes estimates for
amounts recorded for depletion and depreciation of the property, plant and
equipment, financial derivative instruments, asset retirement obligation, unit
based compensation and income taxes.  The ceiling test uses factors
such as estimated reserves, production rates, estimated future petroleum and
natural gas prices and future costs.  Due to the inherent limitations
in metering and the physical properties of storage caverns and pipelines, the
determination of precise volumes of natural gas liquids held in inventory at
such locations is subject to estimation. Actual inventories of natural gas
liquids can only be determined by draining of the caverns.  By their
very nature, these estimates are subject to measurement uncertainty and the
effect on the financial statements of future periods could be
material.
 
 The
estimation of oil and gas reserves is a subjective process.  Forecasts
are based on engineering data, projected future rates of production, estimated
commodity prices, and the timing of future expenditures.  The Trust
expects reserve estimates to be revised based on the results of future drilling
activity, testing, production levels, and economics of recovery based on cash
flow forecasts.
 
 
 3.
                Changes
      in accounting policies and
practices
 
 A.    Changes
in accounting policies
 
 Goodwill
and intangible assets
 
 In the
first quarter of 2009, the Trust adopted CICA Handbook section 3064 “Goodwill
and Intangible assets” which supersedes section 3062 “Goodwill and other
Intangible assets” and section 3450 “Research and Development”.  This
new section established standards for the recognition, measurement and
disclosure of goodwill and intangible assets.  The adoption of this
standard did not have a material impact on the Trust’s consolidated financial
statements.
  
 
 
 B.Recent
accounting pronouncements
 
 International Financial Reporting
Standards
 
 During
2008, the Canadian Accounting Standards Board (AcSB) confirmed that publicly
accountable enterprises will be required to adopt International Financial
Reporting Standards (IFRS) in place of Canadian GAAP for interim and annual
reporting purposes.  The required changeover date is for fiscal years
beginning on or after January 1, 2011.  Management has not yet
finalized its accounting policies and as such is unable to quantify the impact
of adopting IFRS on the financial statements.  In addition, due to
anticipated changes to IFRS and International Accounting Standards prior to
Provident’s adoption of IFRS, management’s plan is subject to change based on
new facts and circumstances.
 
 Business
combinations
 
 In
December of 2008, the CICA released Handbook section 1582 “Business
Combinations”, which replaces existing guidance under section 1581 “Business
Combinations”.  The new standard is intended to converge with
International Financial Reporting Standards.  Under section 1582, the
purchase price in a business combination is based on the fair value of shares
exchanged at the market price on the acquisition date.  Under the
existing standard, the purchase price is based on the market price of shares
over a reasonable period before and after the date of acquisition is agreed upon
and announced.  This new standard also requires that all acquisition
costs be expensed as incurred.  Currently, these costs may be
capitalized as part of the purchase price.  In addition, the new
guidance addresses contingent liabilities, which will be required to be
recognized at fair value on acquisition and subsequently remeasured at each
reporting period until settled.  Under the current standard, only
contingent liabilities that are payable are recognized.  This new
section requires that negative goodwill to be recognized in earnings immediately
rather than the existing standard of reducing non-current assets in the purchase
price allocation.  The new standard applies prospectively to business
combinations on or after January 1, 2011 with earlier adoption
permitted.  The Trust is currently assessing the impact of the new
standard.
 
 
 4.
                Acquisitions
 
 In August
of 2009, the Trust purchased an additional 6.15 percent interest in the Sarnia
fractionation and storage facility for a cash payment of $14.8 million and a
deferred payment of $3.7 million for a facility enhancement planned for 2010.
This increased the Trust’s ownership in the Sarnia fractionator, effective
August 1, 2009, to approximately 16.5 percent, enhancing propane-plus
fractionation capacity in the Empress East system of the Midstream segment by
approximately 7,400 barrels per day.
 
 In 2008,
Provident spent $25.8 million acquiring additional working interests in
Provident Upstream operating areas.
 
 
 5.
                Sale
      of assets
 
 On
September 30, 2009, Provident completed a sale of the operating areas of
Southeast and Southwest Saskatchewan for net proceeds of $225.7 million and a
separate sale of a minor property in the Lloydminster area for $12.8
million.  The proceeds from the sales were credited against the full
cost pool of oil and natural gas properties included in property, plant and
equipment on the Trust’s balance sheet.  No gain or loss was
recognized on these transactions.
 
 On
November 30, 2009, Provident completed a sale of its oil and natural gas assets
in the Lloydminster area for net proceeds of $84.0 million.  The sale
proceeds are comprised of $67.0 million in cash and $17.0 million in equity of
the acquirer.  The proceeds from the sales were credited against the
full cost pool of oil and natural gas properties included in property, plant and
equipment on the Trust’s balance sheet.  No gain or loss was
recognized on this transaction.
   
 6.
                  Property, plant and
      equipment
 Accumulateddepletion
      and
                    
                    
                    Net
      BookAs
      at December 31, 2009
                    
                    Cost
                    
                    
                    depreciation
                    
                    
                    valueOil
      and natural gas properties
                    
                    $
                    2,893,330
                    
                    
                    $
                    1,657,694
                    
                    
                    $
                    1,235,636Midstream
      assets
                    
                    
                    883,840
                    
                    
                    
                    113,820
                    
                    
                    
                    770,020Office
      equipment
                    
                    
                    47,174
                    
                    
                    
                    27,786
                    
                    
                    
                    19,388Total
                    
                    $
                    3,824,344
                    
                    
                    $
                    1,799,300
                    
                    
                    $
                    2,025,044
  Accumulateddepletion
      and
                    
                    
                    Net
      BookAs
      at December 31, 2008
                    
                    Cost
                    
                    
                    depreciation
                    
                    
                    valueOil
      and natural gas properties
                    
                    $
                    3,125,360
                    
                    
                    $
                    1,411,997
                    
                    
                    $
                    1,713,363Midstream
      assets
                    
                    
                    827,172
                    
                    
                    
                    87,674
                    
                    
                    
                    739,498Office
      equipment
                    
                    
                    44,678
                    
                    
                    
                    17,036
                    
                    
                    
                    27,642Total
                    
                    $
                    3,997,210
                    
                    
                    $
                    1,516,707
                    
                    
                    $
                    2,480,503
 
 Costs
associated with unproved properties and major development projects excluded from
costs subject to depletion as at December 31, 2009 totaled $24.7 million
(December 31, 2008 - $93.1 million).  Midstream assets include $43.9
million (2008 - $41.8 million) for products required for line-fill and cavern
bottoms.
 
 An
impairment test calculation was performed on property, plant and equipment at
December 31, 2009 in which the estimated undiscounted future net cash flows
based on estimated future prices associated with the proved reserves exceeded
the carrying amount of oil and gas property, plant and
equipment.
 
 The
following table outlines prices used in the impairment test at December 31,
2009:
  Oil
                  
                  Gas
                  
                  NGLYear
                  
                  $
      /bbl
                  
                  $
      /mcf
                  
                  $
      /bbl2010
                  $
                  65.83
                  
                  $
                  6.04
                  
                  $
                  56.192011
                  $
                  67.42
                  
                  $
                  6.78
                  
                  $
                  59.772012
                  $
                  68.82
                  
                  $
                  7.20
                  
                  $
                  63.572013
                  $
                  71.34
                  
                  $
                  7.53
                  
                  $
                  67.132014
                  $
                  75.09
                  
                  $
                  7.91
                  
                  $
                  71.56Thereafter
      (1)
                  
                  2
                  %
                  
                  2
                  %
                  
                  2
                  %(1)Percentage change represents the increase in each year after 2014
      to the end of the reserve life.  
 7.           Intangible
assets
 Accumulated
                      
                      
                      Net
      BookAs
      at December 31, 2009
                      
                      Cost
                      
                      
                      amortization
                      
                      
                      valueMidstream
      contracts and customer relationships
                      
                      $
                      183,100
                      
                      
                      
                      61,862
                      
                      
                      $
                      121,238Other
      intangible assets - Midstream
                      
                      
                      16,308
                      
                      
                      
                      5,068
                      
                      
                      
                      11,240Total
                      
                      $
                      199,408
                      
                      
                      $
                      66,930
                      
                      
                      $
                      132,478
   Accumulated
                      
                      
                      Net
      BookAs
      at December 31, 2008
                      
                      Cost
                      
                      
                      amortization
                      
                      
                      valueMidstream
      contracts and customer relationships
                      
                      $
                      183,100
                      
                      
                      
                      37,255
                      
                      
                      $
                      145,845Other
      intangible assets - Midstream
                      
                      
                      16,308
                      
                      
                      
                      3,817
                      
                      
                      
                      12,491Total
                      
                      $
                      199,408
                      
                      
                      $
                      41,072
                      
                      
                      $
                      158,336
 
 In 2009,
the Trust recognized an impairment of $12.4 million on a specific Midstream
marketing agreement. The Trust had been amortizing the agreement over a 15 year
period.  The Trust now expects that it is
unlikely
   
 
 that the
agreement will be renewed beyond March 31, 2011 on the same terms.  In
addition, during 2009, the volumes supplied to the Trust under this agreement
were reduced as a result of certain property dispositions completed by the third
party supplier.  The impairment reflects a revision of the
amortization period of this agreement and lower volume expectations for the
remainder of the contract.  The impairment was recognized in the
statement of operations in depletion, depreciation, and accretion
expense.
 
 
 8.
                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.  As at
December 31, 2009 and 2008, the goodwill balance of $100.4 million related
entirely to the Provident Midstream reporting unit.  In 2008, it was
determined that goodwill relating to the Provident Upstream business unit was
impaired and a goodwill impairment of $416.9 million was
recorded.
 
 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.  The impairment test includes a comparison of the net book
value of the Trust’s assets, by reporting units, to the estimated fair value of
the reporting unit.  In 2009, Provident engaged the services of a
third-party evaluator to assist in determining fair value.  Valuation
methodologies included discounted cash flow, a transaction-based approach and a
market-based approach, using trading multiples.  Goodwill is not
amortized.
 
 The Trust
performed its annual goodwill impairment test in the fourth quarter of 2009 and
indicated that the fair value of the Midstream reporting unit was in excess of
the respective carrying value, therefore no write down of goodwill was
required.
 
 
 9.
                Long-term debt
 
 As
      at
                  
                  
                  As
      atDecember
      31, 2009
                  
                  
                  December
      31, 2008Revolving
      term credit facility
                  
                  $
                  264,776
                  
                  
                  $
                  504,685Convertible
      debentures
                  
                  
                  240,486
                  
                  
                  
                  260,994Current
      portion of convertible debentures
                  
                  
                  -
                  
                  
                  
                  (24,871
                  )240,486
                  
                  
                  
                  236,123Total
                  
                  $
                  505,262
                  
                  
                  $
                  740,808
 
 i)
                Revolving term credit
      facility
 
 In 2009,
the Trust’s Canadian term credit facility was reduced by $95 million to $1,030
million (2008 - $1,125 million) due to the asset dispositions in the Upstream
business unit.  Based on the terms and conditions of the credit
facility, Provident has access to $959 million of the total
facility.  The borrowing capacity of the term credit facility is
re-measured quarterly.  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, 2009, $265.0million was drawn on
this facility.
 
 The
credit facility is with a syndicate of banks and is secured by the Trust’s
Midstream assets and Canadian oil and gas properties.  The terms of
the credit facility have a revolving three year period expiring on May 30,
2011.
 
 At
December 31, 2009 the effective interest rate of the outstanding credit facility
was 1.4percent
(2008 - 3.3 percent).  At December 31, 2009 Provident had $27.2
million in letters of credit outstanding (2008 - $35.2 million) that guarantee
Provident’s performance under certain commercial and other
contracts.
  
 
 ii)
                Convertible
      debentures
 
 The Trust
may elect to satisfy interest and principal obligations by the issue of trust
units.  For the year ended December 31, 2009, no debentures were
converted to trust units at the election of debenture holders (2008 – face value
of $0.1 million).  Upon maturity in 2009, the Trust repaid $25.1
million to the holders of its 8.0 percent convertible debentures (2008 - $19.9
million to the holders of 8.75 percent convertible debentures), and the balance
of the equity component of the 8.0 percent convertible debentures, amounting to
$1.3 million (2008 - $1.0 million, related to the 8.75 percent convertible
debentures that matured in 2008), was transferred to contributed
surplus.  Included in the carrying value at December 31, 2009 were
financing costs of $3.0million.  At
December 31, 2009, the fair value of the convertible debentures approximates the
face value of the instruments.  The following table details each
outstanding convertible debenture.
  As
      at
                  
                  
                  
                  As
      atConvertible
      Debentures
                  
                  
                  December
      31, 2009
                  
                  
                  
                  December
      31, 2008ConversionCarrying
                  
                  
                  Face
                  
                  
                  
                  Carrying
                  
                  
                  Face
                  
                  
                  
                  
                  Price
      per($000s
      except conversion pricing)
                  Value(1
                  )
                  
                  Value
                  
                  Value(1
                  )
                  
                  Value
                  
                  Maturity
      Date
                  unit(2
                  )6.5%
      Convertible Debentures
                  
                  
                  $
                  146,028
                  
                  
                  $
                  149,980
                  
                  
                  
                  $
                  143,212
                  
                  
                  $
                  149,980
                  
                  April
      30, 2011
                  
                  
                  
                  14.756.5%
      Convertible Debentures
                  
                  
                  
                  94,458
                  
                  
                  
                  98,999
                  
                  
                  
                  
                  92,911
                  
                  
                  
                  98,999
                  
                  Aug.
      31, 2012
                  
                  
                  
                  13.758.0%
      Convertible Debentures
                  
                  
                  
                  -
                  
                  
                  
                  -
                  
                  
                  
                  
                  24,871
                  
                  
                  
                  25,109
                  
                  July
      31, 2009
                  
                  
                  
                  12.00$
                  240,486
                  
                  
                  $
                  248,979
                  
                  
                  
                  $
                  260,994
                  
                  
                  $
                  274,088
 
 
 10.
                Asset
      retirement obligation
 
 The
Trust’s asset retirement obligation is based on the Trust’s net ownership in
wells, facilities and the midstream assets and represents management’s estimate
of the costs to abandon and reclaim those wells, facilities and midstream assets
as well as an estimate of the future timing of the costs to be
incurred.   Estimated cash flows have been discounted at the
Trust’s average credit-adjusted risk free rate of sevenpercent 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 $307.0 million
(2008 - $348.5 million).  Payments to settle oil and gas asset
retirement obligations occur over the operating lives of the assets estimated to
be over the next 47 years.
 
 The total
undiscounted amount of future cash flows required to settle the midstream asset
retirement obligations is estimated to be $195.5 million (2008 - $166.1
million).  The estimated costs include such activities as dismantling,
demolition and disposal of the facilities as well as remediation and restoration
of the surface land.  Payments to settle the midstream asset
retirement obligations are expected to occur subsequent to the closure of the
facilities and related assets.  Settlement of these obligations is
expected to occur in 28to 38years.
 
 Year
      ended December 31,($000s)
                  
                  2009
                  
                  
                  2008Carrying
      amount, beginning of year
                  
                  $
                  59,432
                  
                  
                  $
                  43,886Acquisitions
                  
                  
                  875
                  
                  
                  
                  440Change
      in estimate
                  
                  
                  10,992
                  
                  
                  
                  15,759Increase
      in liabilities incurred during the year
                  
                  
                  856
                  
                  
                  
                  1,289Settlement
      of liabilities during the year
                  
                  
                  (5,399
                  )
                  
                  
                  (6,381
                  )Decrease
      in liabilities due to sale of assets
                  
                  
                  (9,550
                  )
                  
                  
                  -Accretion
      of liability
                  
                  
                  4,258
                  
                  
                  
                  4,439Carrying
      amount, end of year
                  
                  $
                  61,464
                  
                  
                  $
                  59,432
 
  
 
 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 percent of the simple average
of the closing price of the trust units on the principal market on which the
trust units are quoted for trading during the 10 trading day period commencing
immediately after the date on which the trust units are surrendered for
redemption; and (ii) the closing market price on the principal market on which
the trust units are quoted for trading on the date that the trust units are
surrendered for redemption.
 
 The
aggregate Market Redemption Price payable by the Trust in respect of any trust
units surrendered for redemption during any calendar month shall be satisfied by
way of a cash payment on the last day of the following month.  Total
cash payments for redemption are limited to an annual maximum of
$250,000.  Any excess over the maximum may be satisfied by
distributing notes having an aggregate principal amount equal to the aggregate
Market Redemption Price of the trust units tendered for
redemption.
 
 i)
                2009
      activity
 
 In 2009,
the Trust issued 5.2 million units related to Provident’s DRIP
program.  The increase in unitholders’ contributions associated with
these activities was $28.1million.
 
 ii)
                2008
      activity
 
 In 2008,
the Trust issued 6.5 million units related to Provident’s DRIP program,
conversion of convertible debentures to units and units issued pursuant to
Provident’s Unit Option Plan.  The increase in unitholders’
contributions associated with these activities was $55.7
million.
  Year
      ended December 31,2009
                  
                  
                  
                  
                  
                  2008Number
      of
                  
                  
                  Amount
                  
                  
                  Number
      of
                  
                  
                  AmountTrust
      Units
                  
                  units
                  
                  
                  
                  (000s)
                  
                  
                  units
                  
                  
                  
                  (000s)Balance
      at beginning of year
                  
                  
                  259,087,789
                  
                  
                  $
                  2,806,071
                  
                  
                  
                  252,634,773
                  
                  
                  $
                  2,750,374Issued
      pursuant to unit option plan
                  
                  
                  -
                  
                  
                  
                  -
                  
                  
                  
                  191,448
                  
                  
                  
                  1,790Issued
      pursuant to the distribution reinvestment plan
                  
                  
                  4,913,799
                  
                  
                  
                  25,732
                  
                  
                  
                  5,600,810
                  
                  
                  
                  50,667To
      be issued pursuant to the distribution reinvestment plan
                  
                  
                  335,048
                  
                  
                  
                  2,374
                  
                  
                  
                  655,142
                  
                  
                  
                  3,171Debenture
      conversions
                  
                  
                  -
                  
                  
                  
                  -
                  
                  
                  
                  5,616
                  
                  
                  
                  69Balance
      at end of year
                  
                  
                  264,336,636
                  
                  
                  $
                  2,834,177
                  
                  
                  
                  259,087,789
                  
                  
                  $
                  2,806,071
 
 The basic
and diluted per trust unit amounts for 2009 were calculated based on the
weighted average number of units outstanding of 261,540,079(2008 –
255,177,346).
 
 The
following table reconciles the movement in the contributed surplus
balance.
  Year
      ended December 31,2009
                  
                  
                  2008Contributed
      surplus, beginning of the year
                  
                  $
                  1,695
                  
                  
                  $
                  801Benefit
      on options exercised charged tounitholders’
      contributions
                  
                  
                  -
                  
                  
                  
                  (117
                  )Transferred
      from convertible debentures equitycomponent
      on maturity (see note 9)
                  
                  
                  1,258
                  
                  
                  
                  1,011Contributed
      surplus, end of year
                  
                  $
                  2,953
                  
                  
                  $
                  1,695
 
  
 
 12.
                Unit
      based compensation
 
 Restricted/Performance
units
 
 Certain
employees of the Trust 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 annualized total unitholder
return.
 
 The fair
value estimate associated with the RTUs and PTUs is expensed in the statement of
operations over the vesting period.  At December 31, 2009, $12.2million
(2008 - $9.4 million) is included in accounts payable and accrued liabilities
for this plan and $12.5million
(2008 - $8.6 million) is included in other long-term
liabilities.
 
 The
following table reconciles the expense recorded for RTUs and
PTUs.
  Year
      ended December 31,2009
                  
                  
                  2008Cash
      general and administrative
                  
                  $
                  8,213
                  
                  
                  $
                  8,287Non-cash
      unit based compensation(included
      in general and administrative)
                  
                  
                  6,326
                  
                  
                  
                  (4,117
                  )Strategic
      review and restructuring expenses (note 16)
                  
                  
                  3,254
                  
                  
                  
                  -Production,
      operating and maintenance expense
                  
                  
                  607
                  
                  
                  
                  266$
                  18,400
                  
                  
                  $
                  4,436The
      following table provides a continuity of the Trust’s RTU and PTU
      plans:RTUs
                  
                  
                  PTUsOpening
      balance January 1, 2008
                  
                  
                  849,672
                  
                  
                  
                  2,478,037Grants
                  
                  
                  559,301
                  
                  
                  
                  1,092,697Reinvested
      through notional distributions
                  
                  
                  144,838
                  
                  
                  
                  423,750Exercised
                  
                  
                  (374,474
                  )
                  
                  
                  (551,062
                  )Cancelled
                  
                  
                  (39,502
                  )
                  
                  
                  (43,092
                  )Ending
      balance December 31, 2008
                  
                  
                  1,139,835
                  
                  
                  
                  3,400,330Grants
                  
                  
                  911,263
                  
                  
                  
                  1,813,312Reinvested
      through notional distributions
                  
                  
                  218,283
                  
                  
                  
                  569,119Exercised
                  
                  
                  (530,556
                  )
                  
                  
                  (1,602,482
                  )Cancelled
                  
                  
                  (162,702
                  )
                  
                  
                  (221,157
                  )Ending
      balance December 31, 2009
                  
                  
                  1,576,123
                  
                  
                  
                  3,959,122At
      December 31, 2009, all RTUs and PTUs have been valued at market
      prices.
 
 
 13.
                Income
      taxes
 
 The
future income tax liability is comprised of the
following:
  The
      future income tax liability is comprised of the following:Year
      ended December 31,2009
                  
                  
                  2008Property,
      plant and equipment in excess of tax value
                  
                  $
                  343,095
                  
                  
                  $
                  378,663Asset
      retirement obligation
                  
                  
                  (15,502
                  )
                  
                  
                  (16,863
                  )Financial
      derivative instruments
                  
                  
                  (55,240
                  )
                  
                  
                  (15,123
                  )Non-capital
      losses
                  
                  
                  (105,811
                  )
                  
                  
                  (68,414
                  )Capital
      losses
                  
                  
                  (49,114
                  )
                  
                  
                  (46,544
                  )Other
                  
                  
                  (15,863
                  )
                  
                  
                  (22,294
                  )Valuation
      allowance
                  
                  
                  61,100
                  
                  
                  
                  58,382$
                  162,665
                  
                  
                  $
                  267,807
 
 The
Trust’s valuation allowance applies to capital losses and other temporary
differences that reduce the amount recorded to the expected amount to be
realized.
 
 The
amount and timing of reversals of temporary differences depends on the Trust’s
future operating results, acquisitions and dispositions of assets and
liabilities, and distribution policy.  A significant change in any of
the preceding assumptions could materially affect the Trust’s estimate of the
future tax liability.
 
 The
income tax provision differs from the expected amount calculated by applying the
Trust’s combined federal and provincial/state income tax rate of 29.51 percent
(2008 – 30.96 percent) as follows:
  Year
      ended December 31,2009
                  
                  
                  2008Expected
      income tax recovery, from continuing operations
                  
                  $
                  (57,121
                  )
                  
                  $
                  (6,135
                  )Increase
      (decrease) resulting from:Goodwill
      impairment (permanent difference)
                  
                  
                  -
                  
                  
                  
                  124,992Income
      of the Trust and other
                  
                  
                  (50,237
                  )
                  
                  
                  (142,169
                  )Capital
      taxes
                  
                  
                  2,313
                  
                  
                  
                  3,109Witholding
      tax
                  
                  
                  1,172
                  
                  
                  
                  (498
                  )Income
      tax rate differences
                  
                  
                  (671
                  )
                  
                  
                  (10,484
                  )Income
      tax recovery, from continuing operations
                  
                  $
                  (104,544
                  )
                  
                  $
                  (31,185
                  )
 
 
 14.
                Financial
      instruments
 
 Risk
Management overview
 
 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 Audit
Committee and Board of Directors.
 
 Provident
has established and implemented Risk Management strategies, policies and limits
that are monitored by Provident’s Risk Management group.  The
derivative instruments the Trust uses include put and call options, costless
collars, participating swaps, and fixed price products that settle against
indexed referenced pricing. The purchase of put option contracts effectively
create a floor price for the commodity, while allowing for full participation if
prices increase.  The purchase of call options allow for a commodity
to be purchased at a fixed price at the option of the contract
holder.  Costless collars are contracts that provide a floor and a
ceiling price and allowing participation within a set
range.  Participating swaps are contracts that provide a floor and
also
  
 
 provide a
ceiling for a certain percentage of the volume of the contract.  Fixed
price swaps are contracts that specify a fixed price at which a certain volume
of product will be bought or sold at in the future.
 
 The Risk
Management group monitors risk exposure by generating and reviewing
mark-to-market reports and counterparty credit exposure of Provident’s
outstanding derivative contracts.  Additional monitoring activities
include reviewing available derivative positions, regulatory changes and bank
and analyst reports.
 
 Provident’s
commodity price risk management program utilizes derivative instruments to
provide for protection against lower commodity prices and product margins, as
well as fluctuating interest and foreign exchange rates.  Provident
may also use derivative instruments to protect acquisition
economics.  The program is designed to stabilize cash flows in order
to support cash distributions, capital programs and bank
financing.  The risk management strategy protects a percentage of
Provident’s oil and natural gas production against a decline in commodity
prices.  Provident seeks to use products that allow participation in a
rising commodity price environment where possible and economic.  The
program provides price stabilization and protection of a percentage of inventory
values and fractionation spread margin associated with the midstream business
unit.  As well, the Provident risk management strategy reduces foreign
exchange risk due to the exposure arising from the conversion of U.S. dollars
into Canadian dollars.
 
 Fair
Values
 
 During
2009, CICA Handbook Section 3862, Financial Instruments – Disclosures (“Section
3862”), was amended to require disclosures about the inputs to fair value
measurements, including their classification within a hierarchy that prioritizes
the inputs to fair value measurement.  The three levels of the fair
value hierarchy are:
 
 ·
                Level
      1 – Unadjusted quoted prices in active markets for identical assets or
      liabilities;
 ·
                Level
      2 – Inputs other than quoted prices that are observable for the asset or
      liability either directly or indirectly;
and
 ·
                Level
      3 – Inputs that are not based on observable market
  data.
 
 Provident’s
financial derivative instruments are the only financial instrument carried at
fair value as at December 31, 2009 and are Level 2 instruments.  The
fair values of financial derivative instruments are determined by reference to
independent monthly forward settlement prices, interest rate yield curves,
currency rates, and volatility rates at the period-end dates.  All of
Provident’s financial derivative instruments are executed in liquid
markets.
 
 Provident
has also reflected management’s assessment of nonperformance risk, including
credit risk, into the fair value measurement. In evaluating the credit risk
component of nonperformance risk, Provident has considered prevailing market
credit spreads.
  
 
 TotalHeld
      for
                  
                  
                  Available
                  
                  
                  Loans
      and
                  
                  
                  Other
                  
                  
                  CarryingAs
      at December 31, 2009
                  
                  Trading
                  
                  
                  for
      Sale
                  
                  
                  Receivables
                  
                  
                  Liabilities
                  
                  
                  ValueAssetsCash
      and cash equivalents
                  
                  $
                  7,187
                  
                  
                  $
                  -
                  
                  
                  $
                  -
                  
                  
                  $
                  -
                  
                  
                  $
                  7,187Accounts
      receivable
                  
                  
                  -
                  
                  
                  
                  -
                  
                  
                  
                  216,786
                  
                  
                  
                  -
                  
                  
                  
                  216,786Financial
      derivative instruments-
      current assets
                  
                  
                  5,314
                  
                  
                  
                  -
                  
                  
                  
                  -
                  
                  
                  
                  -
                  
                  
                  
                  5,314Investments
      and other long-term assets
                  
                  
                  -
                  
                  
                  
                  18,733
                  
                  
                  
                  -
                  
                  
                  
                  -
                  
                  
                  
                  18,733$
                  12,501
                  
                  
                  $
                  18,733
                  
                  
                  $
                  216,786
                  
                  
                  $
                  -
                  
                  
                  $
                  248,020LiabilitiesAccounts
      payable and accrued liabilities
                  
                  $
                  -
                  
                  
                  $
                  -
                  
                  
                  $
                  -
                  
                  
                  $
                  221,417
                  
                  
                  $
                  221,417Cash
      distributions payable
                  
                  
                  -
                  
                  
                  
                  -
                  
                  
                  
                  -
                  
                  
                  
                  13,468
                  
                  
                  
                  13,468Financial
      derivative instruments-
      current liabilities
                  
                  
                  86,441
                  
                  
                  
                  -
                  
                  
                  
                  -
                  
                  
                  
                  -
                  
                  
                  
                  86,441Long-term
      debt - revolving term credit facilities
                  
                  
                  -
                  
                  
                  
                  -
                  
                  
                  
                  -
                  
                  
                  
                  264,776
                  
                  
                  
                  264,776Long-term
      debt - convertible debentures
                  
                  
                  -
                  
                  
                  
                  -
                  
                  
                  
                  -
                  
                  
                  
                  240,486
                  
                  
                  
                  240,486Financial
      derivative instruments-
      long -term liabilities
                  
                  
                  103,403
                  
                  
                  
                  -
                  
                  
                  
                  -
                  
                  
                  
                  -
                  
                  
                  
                  103,403Other
      long-term liabilities
                  
                  
                  -
                  
                  
                  
                  -
                  
                  
                  
                  -
                  
                  
                  
                  12,496
                  
                  
                  
                  12,496$
                  189,844
                  
                  
                  $
                  -
                  
                  
                  $
                  -
                  
                  
                  $
                  752,643
                  
                  
                  $
                  942,487
 
 
 Except as
disclosed in note 9in
connection with the convertible debentures, there were no significant
differences between the carrying value of these financial instruments and their
estimated fair value as at December 31, 2009.
 
 
 The
following table is a summary of the net financial derivative instruments
liability:
 
 As
      at
                  
                  
                  As
      atDecember
      31,
                  
                  
                  December
      31,($000s)
                  
                  2009
                  
                  
                  2008Provident
      UpstreamCrude
      Oil
                  
                  $
                  826
                  
                  
                  $
                  (12,521
                  )Natural
      Gas
                  
                  
                  1,545
                  
                  
                  
                  (3,285
                  )Provident
      Midstream
                  
                  
                  181,890
                  
                  
                  
                  70,476Corporate
                  
                  
                  269
                  
                  
                  
                  -Total
                  
                  $
                  184,530
                  
                  
                  $
                  54,670
 
 
 Market
Risk
 
 Market
risk is the risk that the fair value of a financial instrument will fluctuate
because of changes in market prices. Market risk generally comprises of price
risk, currency risk and interest rate risk.
 
 a)      Price
risk
 
 Commodity
Price Risk Management Program
 
 The
decisions to enter into financial derivative positions and to execute the 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.
   
 
 Upstream
  Provident’s
risk management program employs derivative instruments, such as puts and
participating swaps, to protect a floor level of Provident’s revenue on a
portion of the oil and gas sold.  These instruments may enable
Provident to retain various levels of participation to the extent oil and gas
prices rise.
 
 The major
identified risks for the Upstream business line are commodity price volatility
and market location and product quality differentials. Provident addresses these
risks using a risk management program designed to protect a portion of its cash
flow in order to support continued unitholder distributions, capital programs
and bank financing.
 
 Midstream
 
 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 spread ratios.  Frac spread ratio is
the ratio between crude oil prices and natural gas prices.  There is
also a differential between NGL product prices (propane, butane and condensate)
and crude oil prices.
 
 Provident
responds to these risks using a risk management program that protects a
margin or floor level of operating income on a portion of its NGL inventory and
production, while retaining some ability to participate in a widening margin
environment.  For the longer-term, Provident uses crude oil contracts
in place of NGLs.  Provident may replace these contracts with NGL
product contracts as market conditions allow. This strategy enables Provident to
mitigate commodity price risk related to its NGL production business up to
approximately four years into the future.
 
 b)
                Currency
      risk
 
 Provident’s
oil, natural gas and NGL sales are exposed to both positive and negative effects
of fluctuations in the Canadian/U.S. 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 business
lines.
 
 Provident
regularly sells or purchases forward a portion of expected U.S.
cashflows.  Provident’s strategy also manages the exposure it has to
fluctuations in the U.S./Canadian dollar exchange rate when the underlying
commodity price is based upon a U.S. index price.  Provident may also
use derivative products that provide for protection against a stronger Canadian
dollar, while allowing it to participate if the currency weakens relative to the
U.S. dollar.
 
 c)
                Interest
      rate risk
 
 The
Trust’s revolving term credit facilities bear interest at a floating
rate.  Using debt levels as at December 31, 2009, an increase/decrease
of 50 basis points in the lender’s base rate would result in an
increase/decrease of annual interest expense of approximately $1.3million.  The
Trust has mitigated this risk by entering into interest rate financial
derivative contracts for a portion of the outstanding long term
debt.  The contracts settle against Canadian Bankers Acceptance CDOR
rates.
 
 Financial
derivative sensitivity analysis
 
 The
following table shows the impact on unrealized gain (loss) on financial
derivative instruments if the underlying risk variables of the financial
derivative instruments changed by a specified amount, with other variables held
constant.
  
 
 ($
      000s)
                  
                  
                  +
      Change
                  
                  
                  -
      ChangeProvident
      UpstreamCrude
      Oil
                  (WTI
      +/- $10.00 per bbl)
                  
                  $
                  (259
                  )
                  
                  $
                  490Natural
      Gas
                  (AECO
      +/- $1.00 per gj)
                  
                  
                  (1,326
                  )
                  
                  
                  2,915Foreign
      exchange
                  (FX
      rate +/- $0.01)
                  
                  
                  (202
                  )
                  
                  
                  203Provident
      MidstreamFrac
      spread relatedCrude
      Oil
                  (WTI
      +/- $10.00 per bbl)
                  
                  $
                  (74,887
                  )
                  
                  $
                  75,054Natural
      Gas
                  (AECO
      +/- $1.00 per gj)
                  
                  
                  46,731
                  
                  
                  
                  (46,565
                  )NGL's
      (includes propane, butane)
                  (Belvieu
      +/- US $0.15 per gal)
                  
                  
                  (1,488
                  )
                  
                  
                  1,487Foreign
      Exchange ($U.S. vs $Cdn)
                  (FX
      rate +/- $ 0.01)
                  
                  
                  (1,386
                  )
                  
                  
                  1,385Inventory,
      margin and otherCrude
      Oil
                  (WTI
      +/- $10.00 per bbl)
                  
                  
                  (4,389
                  )
                  
                  
                  4,388NGL's
      (includes propane, butane, natural gasoline)
                  (Belvieu
      +/- US $0.15 per gal)
                  
                  
                  2,633
                  
                  
                  
                  (2,632
                  )Electricity
                  (AESO
      +/- $5.00 per MW/h
                  
                  
                  437
                  
                  
                  
                  (437
                  )CorporateInterest
      Rate
                  (Rate
      +/- 50 basis points)
                  
                  $
                  1,765
                  
                  
                  $
                  (1,765
                  )
 
 Liquidity
Risk
 
 Liquidity
risk is the risk the Trust will not be able to meet its financial obligations as
they come due. The Trust’s approach to managing liquidity risk is to ensure that
it always has sufficient cash and credit facilities to meet its obligations when
due, without incurring unacceptable losses or damage to the Trust’s
reputation.
 
 Management
typically forecasts cash flows for a period of twelve months to identify
financing requirements. These requirements are then addressed through a
combination of committed and demand credit facilities and access to capital
markets, as discussed in note 15.
 
 The
following table outlines the timing of the cash outflows relating to financial
liabilities.
 
 As
      at December 31, 2009
                  
                  
                  
                  
                  Payment
      due by periodLess
      than($000s)
                  
                  Total
                  
                  
                  1
      year
                  
                  
                  1
      to 3 years
                  
                  
                  3
      to 5 yearsAccounts
      payable and accrued liabilities
                  
                  $
                  221,417
                  
                  
                  $
                  221,417
                  
                  
                  $
                  -
                  
                  
                  $
                  -Cash
      distributions payable
                  
                  
                  13,468
                  
                  
                  
                  13,468
                  
                  
                  
                  -
                  
                  
                  
                  -Financial
      derivative instruments - current
                  
                  
                  86,441
                  
                  
                  
                  86,441
                  
                  
                  
                  -
                  
                  
                  
                  -Long-term
      debt - revolving term credit facilities (1)(2)
                  
                  
                  270,256
                  
                  
                  
                  3,710
                  
                  
                  
                  266,546
                  
                  
                  
                  -Long-term
      debt - convertible debentures (2)
                  
                  
                  279,138
                  
                  
                  
                  16,184
                  
                  
                  
                  262,954
                  
                  
                  
                  -Long-term
      financial derivative instruments
                  
                  
                  103,403
                  
                  
                  
                  -
                  
                  
                  
                  101,578
                  
                  
                  
                  1,825Other
      long-term liabilities
                  
                  
                  12,496
                  
                  
                  
                  -
                  
                  
                  
                  12,496
                  
                  
                  
                  -Total
                  
                  $
                  986,619
                  
                  
                  $
                  341,220
                  
                  
                  $
                  643,574
                  
                  
                  $
                  1,825
 (1)
                  The
      terms of the Canadian credit facility have a revolving three year period
      expiring on May 30, 2011.
 (2)
                  Includes
      associated interest and principal
payments.
 
 Credit
Risk
 
 Provident's
Credit Policy governs the activities undertaken to mitigate the risks associated
with counterparty (customer) non-payment.  The Policy requires a
formal credit review for counterparties entering into a commodity contract with
Provident.  This review determines an approved credit
limit.  Activities undertaken include regular monitoring of
counterparty exposures to approved credit limits, financial review of all active
counterparties, utilizing master netting arrangements and International Swap
Dealers Association (ISDA) agreements and obtaining financial assurances where
warranted.  Financial assurances include guarantees, letters of credit
and cash.  In addition, Provident has a diversified base of
creditors.
   
 
 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 management’s assessment of the creditworthiness of such
counterparties.  The carrying value of accounts receivable reflects
management's assessment of the associated credit
risks.
 
 Settlement
of financial derivative contracts
 
 The
following table summarizes the impact of financial derivative contracts settled
during the years ended December 31, 2009 and 2008 that are included in realized
loss on financial derivative instruments.
  Year
      ended December 31,Realized
      gain (loss) on financial derivative instruments
                  
                  2009
                  
                  
                  2008($
      000s except volumes)
                  
                  
                  
                  
                  Volume
      (1)
                  
                  
                  
                  
                  
                  Volume
      (1)Provident
      UpstreamCrude
      Oil
                  
                  $
                  8,052
                  
                  
                  
                  0.8
                  
                  
                  $
                  (11,113
                  )
                  
                  
                  1.6Natural
      gas
                  
                  
                  8,336
                  
                  
                  
                  6.1
                  
                  
                  
                  11
                  
                  
                  
                  10.9Provident
      MidstreamCrude
      Oil
                  
                  
                  29,007
                  
                  
                  
                  4.1
                  
                  
                  
                  (135,602
                  )
                  
                  
                  4.2Natural
      gas
                  
                  
                  (95,188
                  )
                  
                  
                  23.0
                  
                  
                  
                  (16,978
                  )
                  
                  
                  26.8NGL's
      (includes propane, butane)
                  
                  
                  5,072
                  
                  
                  
                  0.8
                  
                  
                  
                  25,902
                  
                  
                  
                  2.3Foreign
      Exchange
                  
                  
                  (3,505
                  )
                  
                  
                  -
                  
                  
                  
                  5,387
                  
                  
                  
                  -Electricity
                  
                  
                  (1,276
                  )
                  
                  
                  -
                  
                  
                  
                  2,374
                  
                  
                  
                  -CorporateInterest
      Rate (2)
                  
                  
                  (1,137
                  )
                  
                  
                  -
                  
                  
                  
                  -
                  
                  
                  
                  -Realized
      loss on financial derivative instruments
                  
                  $
                  (50,639
                  )
                  
                  
                  -
                  
                  
                  $
                  (130,019
                  )
 (1)
                  T
      he above table represents aggregate net volumes that were bought/sold over
      the periods. Crude oil and NGL volumes are listed in millions of barrels
      and natural gas is listed in millions of
  gigajoules.
 (2)
                  Realized
      gains and losses on corporate related interest rate contracts are
      allocated to the reporting segments for segmented reporting
      purposes.
 
 In
addition, the Trust recorded a loss of $0.2 million (2008 - $26.8 million gain)
on corporate foreign exchange contracts.  The amounts are included in
foreign exchange loss (gain) and other on the consolidated statement of
operations and are allocated to the reporting
segments.
 
 The
contracts in place at December 31, 2009 are summarized in the following
tables:
 
 Provident
      UpstreamVolumeYear
      Product
                  (Buy)/Sell
                  Terms
                  Effective
      Period2010
      Natural Gas
                  13,359
                  Gjpd
                  Puts
      Cdn $4.79 per gj (3)
                  January
      1 - December 315,000
                  Gjpd
                  Participating
      Swap Cdn $4.50 per gj (Average Participation 75% above the floor
      price)
                  April
      1 - October 31Crude
      Oil
                  1,200
                  Bpd
                  Puts
      US $60.00 per bbl (5)
                  January
      1 - December 31Foreign
      Exchange
                  
                  
                  Sell
      US $1,691,667 per month @ 1.115 (14)
                  January
      1 - December 31
 
  
 
 Provident
      MidstreamVolumeYear
      Product
                  (Buy)/Sell
                  Terms
                  
                  Effective
      Period2010
                  Crude
      Oil
                  (1,588
                  )
                  Bpd
                  US
      $77.75 per bbl (11)
                  
                  January
      1 - March 316,272
                  
                  Bpd
                  Cdn
      $73.19 per bbl
                  
                  January
      1 - December 31500
                  
                  Bpd
                  US
      $66.65 per bbl
                  
                  January
      1 - December 311,000
                  
                  Bpd
                  US
      $71.97 per bbl (13)
                  
                  January
      1 - December 311,750
                  
                  Bpd
                  Costless
      Collar US $61.63 floor, US $66.56 ceiling
                  
                  January
      1 - December 31462
                  
                  Bpd
                  Participating
      Swap Cdn $76.98 per bbl (Average Participation 37% above the floor
      price)
                  
                  January
      1 - December 31857
                  
                  Bpd
                  Participating
      Swap US $74.88 per bbl (Average Participation 48% above the floor
      price)
                  
                  January
      1 - December 31Natural
      Gas
                  (48,315
                  )
                  Gjpd
                  Cdn
      $7.77 per gj
                  
                  January
      1 - December 31(5,756
                  )
                  Gjpd
                  Participating
      Swap Cdn $7.77 per gj (Average Participation 28% below the ceiling
      price)
                  
                  January
      1 - December 31Propane
                  875
                  
                  Bpd
                  US
      $0.75 per gallon (7)
                  
                  January
      1 - March 311,683
                  
                  Bpd
                  US
      $1.076 per gallon (6)(11)
                  
                  January
      1 - March 311,695
                  
                  Bpd
                  US
      $1.155 per gallon (6)(12)
                  
                  January
      1 - February 28Natural
      Gasoline
                  (1,000
                  )
                  Bpd
                  US
      $1.41 per gallon (9)(13)
                  
                  January
      1 - December 31Normal
      Butane
                  (1,500
                  )
                  Bpd
                  US
      $0.76 per gallon (8)(13)
                  
                  January
      1 - March 31833
                  
                  Bpd
                  US
      $1.353 per gallon (8)(11)
                  
                  January
      1 - March 31Electricity
                  (10
                  )
                  MW/hpd
                  Cdn
      $47.475 per MW/h (10)
                  
                  January
      1 - December 31Foreign
      Exchange
                  
                  
                  
                  Sell
      US $826,875 per month @ 1.1578 (14)
                  
                  January
      1 - March 31Sell
      US $4,773,059 per month @ 1.1110 (14)
                  
                  January
      1 - December 31Sell
      US $582,821 per month @ 1.0159 (14)
                  
                  January
      1 - August 31Sell
      US $1,420,921 per month @ 0.9781 (14)
                  
                  July
      1 - August 31Sell
      US $587,903 per month @ 1.0165 (14)
                  
                  July
      1 - November 30Sell
      US $2,254,103 per month @ 0.9578 (14)
                  
                  September
      1 - October 31Sell
      US $2,394,058 per month @ 1.0154 (14)
                  
                  September
      1 - November 30Sell
      US $629,673 per month @ 1.0165 (14)
                  
                  November
      1 - December 312011
                  Crude
      Oil
                  5,534
                  
                  Bpd
                  Cdn
      $71.73 per bbl
                  
                  January
      1 - December 311,005
                  
                  Bpd
                  Costless
      Collar US $60.64 floor, US $73.45 ceiling
                  
                  January
      1 - September 30416
                  
                  Bpd
                  Participating
      Swap Cdn $84.38 per bbl (Average Participation 25% above the floor
      price)
                  
                  October
      1 - December 31250
                  
                  Bpd
                  Participating
      Swap US $63.00 per bbl (Average Participation 64% above the floor
      price)
                  
                  January
      1 - December 31Natural
      Gas
                  (41,747
                  )
                  Gjpd
                  Cdn
      $7.32 per gj
                  
                  January
      1 - December 31(2,337
                  )
                  Gjpd
                  Participating
      Swap Cdn $8.28 per gj (Average Participation 25% below the ceiling
      price)
                  
                  October
      1 - December 31Foreign
      Exchange
                  
                  
                  
                  Sell
      US $479,063 per month @ 0.9725 (14)
                  
                  January
      1 - December 31Sell
      US $980,417 per month @ 1.0805 (14)
                  
                  January
      1 - June 30Sell
      US $3,588,000 per month @ 1.0918 (14)
                  
                  July
      1 - September 302012
                  Crude
      Oil
                  3,637
                  
                  Bpd
                  Cdn
      $72.57 per bbl
                  
                  January
      1 - December 311,445
                  
                  Bpd
                  Participating
      Swap Cdn $85.19 per bbl (Average Participation 27% above the floor
      price)
                  
                  February
      1 - December 311,352
                  
                  Bpd
                  Participating
      Swap US $72.22 per bbl (Average Participation 51% above the floor
      price)
                  
                  March
      1 - December 31Natural
      Gas
                  (25,717
                  )
                  Gjpd
                  Cdn
      $7.24 per gj
                  
                  January
      1 - December 31(9,578
                  )
                  Gjpd
                  Participating
      Swap Cdn $8.55 per gj (Average Participation 28% below the ceiling
      price)
                  
                  February
      1 - December 31Foreign
      Exchange
                  
                  
                  
                  Sell
      US $2,016,783 per month @ 1.0119 (14)
                  
                  March
      1 - March 31Sell
      US $1,041,721 per month @ 0.9413 (14)
                  
                  April
      1 - October 31Sell
      US $681,260 per month @ 0.9850 (14)
                  
                  May
      1 - October 31Sell
      US $1,437,986 per month @ 0.9659 (14)
                  
                  July
      1 - December 31Sell
      US $1,634,227 per month @ 0.9829 (14)
                  
                  October
      1 - December 31Sell
      US $1,420,538 per month @ 0.9995 (14)
                  
                  November
      1 - December 312013
                  Crude
      Oil
                  250
                  
                  Bpd
                  Cdn
      $75.32 per bbl
                  
                  January
      1 - January 311,250
                  
                  Bpd
                  Participating
      Swap Cdn $84.90 per bbl (Average Participation 25% above the floor
      price)
                  
                  January
      1 - March 31758
                  
                  Bpd
                  Participating
      Swap US $85.62 per bbl (Average Participation 30% above the floor
      price)
                  
                  January
      1 - March 31Natural
      Gas
                  (7,025
                  )
                  Gjpd
                  Cdn
      $7.19 per gj
                  
                  January
      1 - January 31(9,524
                  )
                  Gjpd
                  Participating
      Swap Cdn $8.87 per gj (Average Participation 22% below the ceiling
      price)
                  
                  January
      1 - March 31Foreign
      Exchange
                  
                  
                  
                  Sell
      US $1,651,990 per month @ 0.9829 (14)
                  
                  January
      1 - January 31Sell
      US $1,397,250 per month @ 0.9995 (14)
                  
                  January
      1 - March 31
 
  
  CorporateVolumeYear
      Product
                  
                  (Buy)/Sell
                  Terms
                  Effective
      PeriodInterest
      Rate
                  
                  $
                  200,000,000
                  
                  Notional
      (Cdn$)
                  Pay
      Average Fixed rate of 1.1885% (15)
                  Jan
      1 2010 - May 31 2011$
                  50,000,000
                  
                  Notional
      (Cdn$)
                  Pay
      Average Fixed rate of 1.1950% (16)
                  Jan
      1 2010 - May 31 2011
 (1)
                  T
      he 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)
                  Natural
      gas put options provide a "floor" price for the gas quantities contracted.
      Floor price is strike less premium. Provident receives market price above
      the "floor".
 (4)
                  Crude
      Oil contracts are settled against NYMEX WT I calendar
    average.
 (5)
                  Crude
      oil put options provide a "floor" price for the oil quantities contracted.
      Floor price is strike less premium. P rovident receives market price above
      the "floor".
 (6)
                  Propane
      contracts are settled against Belvieu C3 T ET
..
 (7)
                  Propane
      contracts are settled against Conway In-Well
C3.
 (8)
                  Normal
      Butane contracts are settled against Belvieu NC4 NON-T ET
  .
 (9)
                  Natural
      Gasoline contracts are settled against Belevieu NON-T ET Natural
      Gasoline.
 (10)
                  Electricity
      contracts are settled against the hourly price of electricity as published
      by the AESO in $/MWh.
 (11)
                  Conversion
      of Crude Oil BT U contracts to
liquids.
 (12)
                  Midstream
      inventory price stabilization
contracts.
 (13)
                  Midstream
      buy/sell contracts.
 (14)
                  US
      Dollar forward contracts are settled against the Bank of Canada noon rate
      average. Selling notional US dollars for Canadian dollars at a fixed
      exchange rate results in a fixed Canadian dollar price for the hedged
      commodity.
 (15)
                  Interest
      rate forward contract settles quarterly against 1M CAD BA CDOR interest
      rate.
 (16)
                  Interest
      rate forward contract settles quarterly against 3M CAD BA CDOR interest
      rate.
 
 15.
                Capital
      management
 
 Provident
considers its total capital to be comprised of net debt and Unitholders’
Equity.  Net debt is comprised of long-term debt and working capital
surplus, excluding balances for the current portion of financial derivative
instruments.  The balance of these items at December 31, 2009 and
December 31, 2008 were as follows:
 
 As
      at
                  
                  
                  As
      atDecember
      31,
                  
                  
                  December
      31,($000s)
                  
                  2009
                  
                  
                  2008Working
      capital surplus (1)
                  
                  $
                  (31,152
                  )
                  
                  $
                  (39,041
                  )Long-term
      debt (including current portion)
                  
                  
                  505,262
                  
                  
                  
                  765,679Net
      debt
                  
                  
                  474,110
                  
                  
                  
                  726,638Unitholders'
      equity
                  
                  
                  1,381,399
                  
                  
                  
                  1,636,347Total
      capitalization
                  
                  $
                  1,855,509
                  
                  
                  $
                  2,362,985Net
      debt to total capitalization
                  
                  
                  26
                  %
                  
                  
                  31
                  %(1)The working capital surplus excludes balances for the current
      portion of financial derivative instruments.
 
 
 Provident’s
primary objective for managing capital is to maximize long-term Unitholder value
by:
 
 ·
                providing
      an appropriate return to unitholders relative to the risk of Provident’s
      underlying assets; and
 ·
                ensuring
      financing capacity for Provident’s internal development opportunities and
      acquisitions of energy related assets that are expected to add value to
      our Unitholders.
 
 Provident
makes adjustments to its capital structure based on economic conditions and the
Trust’s planned requirements.  Provident has the ability to adjust its
capital structure by issuing new equity or debt, controlling the amount it
returns to unitholders, and making adjustments to its capital expenditure
program.  Provident relies on cash flow from operations, external
lines of credit and access to equity markets to fund capital programs and
acquisitions.
 
 The Trust
is subject to certain capital growth restrictions as a result of the Canadian
trust tax legislation passed in June 2007 and effective January 1,
2011.  The restrictions provide that “normal growth” would include
equity growth within certain “safe harbour” limits, measured by reference to the
Trust’s market capitalization as of the end of trading on October 31,
2006.  These rules limit the amount of Unitholders’ capital that can
be issued by
  
 
 the Trust
in 2010.  If the maximum equity growth allowed is exceeded, the Trust
may be subject to trust taxation prior to 2011.  The Trust has $2.2
billion remaining under these safe harbour limits for normal growth capital
allowed in 2010.
 
 
 16.
                Strategic
      review and restructuring expenses
 
 In
February, 2008 the Trust announced a strategic review process to evaluate all of
Provident’s business segments.  During the review, it was determined
that the sale of the United States oil and natural gas production (USOGP)
business was an important step in the process (see note 17).  In 2009,
Provident completed an internal reorganization to improve the efficiency and
competitiveness of the businesses and identified certain non-strategic assets
for divestiture (see notes 5 and 19).  The reorganization and
divestitures resulted in staff reductions at all levels of the organization,
including senior management.  For the year ended December 31, 2009,
strategic review and restructuring costs were $12.3million
(2008 - $3.6 million).  The costs are comprised primarily of
severance, consulting and legal costs.
 
 
 17.
                Discontinued
      operations (USOGP)
 
 Effective
in the first quarter of 2008, Provident’s USOGP business was accounted for as
discontinued operations.  The USOGP business was sold in June and
August of 2008.
 
 Quicksilver
Resources Inc. ("Quicksilver") filed a lawsuit on October 31, 2008 against
BreitBurn Energy Partners, L.P. (the MLP), certain of its directors (including
three Provident nominees), and Provident.  The MLP was part of the
USOGP business.  The claim relates to a transaction between the MLP
and Quicksilver and certain other MLP matters. Quicksilver alleges, among other
things, that it was induced to enter into a contribution agreement pursuant to
which it contributed assets to the MLP by false representations as to
Provident’s relationship with the MLP.  The transaction involved the
issuance by the MLP to Quicksilver of approximately U.S. $700 million of units
of the MLP.   In February of 2010, Provident agreed to settle all
existing litigation with Quicksilver.  The cost of settlement is
covered by insurance.
 
 The
following table shows information about net income from
USOGP.
  The
      following table shows information about net income from
USOGP.Net
      income from discontinued operations
                  
                  Year
      ended December 31,Canadian
      dollars (000's)
                  
                  2009
                  
                  
                  2008Revenue
                  
                  $
                  -
                  
                  
                  $
                  303,146Loss
      from discontinued operations before taxes, non-controllinginterests
      and impact of sale of discontinued operations
                  
                  
                  -
                  
                  
                  
                  (237,233
                  )Gain
      on sale of discontinued operations
                  
                  
                  -
                  
                  
                  
                  263,618Foreign
      exchange loss related to sale of discontinued operations
                  
                  
                  -
                  
                  
                  
                  (57,062
                  )Current
      tax expense
                  
                  
                  -
                  
                  
                  
                  (178,708
                  )Future
      income tax recovery
                  
                  
                  -
                  
                  
                  
                  151,975Non-controlling
      interests
                  
                  
                  -
                  
                  
                  
                  203,434Net
      income from discontinued operations
                  
                  $
                  -
                  
                  
                  $
                  146,024
 
 18.
                Commitments
 
 Provident
has entered into operating leases for offices that extend through June
2022.  In relation to the Midstream segment, Provident is committed to
minimum lease payments under the terms of various tank car leases for five
years.  Additionally, under an arrangement to use a third party
interest in the Younger Plant, Provident has a commitment to make payments
calculated with reference to a number of variables including return on
capital.
 
  
 
 Future
minimum lease payments under non-cancelable operating leases are as
follows:
 
 As
      at December 31, 2009
                  
                  
                  
                  
                  Payment
      due by periodLess
      than($
      millions)
                  
                  Total
                  
                  
                  1
      year
                  
                  
                  1
      to 3 years
                  
                  
                  3
      to 5 yearsOperating
      LeasesOffice
      leases
                  
                  $
                  29.7
                  
                  
                  $
                  5.9
                  
                  
                  $
                  11.5
                  
                  
                  $
                  12.3Rail
      tank cars
                  
                  
                  22.0
                  
                  
                  
                  8.3
                  
                  
                  
                  11.1
                  
                  
                  
                  2.6Younger
      plant
                  
                  
                  18.1
                  
                  
                  
                  3.9
                  
                  
                  
                  7.4
                  
                  
                  
                  6.8Total
                  
                  $
                  69.8
                  
                  
                  $
                  18.1
                  
                  
                  $
                  30.0
                  
                  
                  $
                  21.7
 
 
 19.
                Subsequent
      event
 
 Upstream
asset disposition
 
 On March
1, 2010, the Trust closed its previously announced sale of oil and natural gas
assets in West Central Alberta for cash consideration of $177 million, after
closing adjustments.  The transaction had an effective date of October
1, 2009.  The proceeds from the sale will be credited against the full
cost pool of oil and natural gas properties included in property, plant and
equipment on the Trust’s balance sheet.  No gain or loss will be
recognized on this transaction.  On closing, Provident’s Canadian term
credit facility and Provident’s access to the total facility were reduced by $50
million to $980 million and $909 million
respectively.
 
 
 20.
                Segmented
      information
 
 The
Trust’s business activities are conducted through two business segments:
Canadian oil and natural gas production (“Provident Upstream”) and Provident
Midstream.
 
 Provident
Upstream includes exploitation, development and production of crude oil and
natural gas reserves.  Provident Midstream includes processing,
extraction, transportation, loading, storage and marketing of natural gas
liquids.
 
 Geographically
the Trust operates in Canada in the Upstream business segment and in Canada and
the USA in the Midstream business.
 
  
 
 Year
      ended December 31, 2009Provident
                  
                  
                  ProvidentUpstream
                  
                  
                  Midstream
      (1)
                  
                  
                  TotalRevenueGross
      production revenue
                  
                  $
                  303,067
                  
                  
                  $
                  -
                  
                  
                  $
                  303,067Royalties
                  
                  
                  (41,575
                  )
                  
                  
                  -
                  
                  
                  
                  (41,575
                  )Product
      sales and service revenue
                  
                  
                  -
                  
                  
                  
                  1,630,491
                  
                  
                  
                  1,630,491Realized
      gain (loss) on financial derivative instruments
                  
                  
                  16,104
                  
                  
                  
                  (66,743
                  )
                  
                  
                  (50,639
                  )277,596
                  
                  
                  
                  1,563,748
                  
                  
                  
                  1,841,344ExpensesCost
      of goods sold
                  
                  
                  -
                  
                  
                  
                  1,305,191
                  
                  
                  
                  1,305,191Production,
      operating and maintenance
                  
                  
                  119,437
                  
                  
                  
                  14,532
                  
                  
                  
                  133,969Transportation
                  
                  
                  11,482
                  
                  
                  
                  23,985
                  
                  
                  
                  35,467Foreign
      exchange loss (gain) and other
                  
                  
                  (674
                  )
                  
                  
                  1,802
                  
                  
                  
                  1,128General
      and administrative
                  
                  
                  30,725
                  
                  
                  
                  31,297
                  
                  
                  
                  62,022Strategic
      review and restructuring
                  
                  
                  7,633
                  
                  
                  
                  4,624
                  
                  
                  
                  12,257168,603
                  
                  
                  
                  1,381,431
                  
                  
                  
                  1,550,034Earnings
      before interest, taxes, depletion, depreciation,accretion
      and other non-cash items
                  
                  
                  108,993
                  
                  
                  
                  182,317
                  
                  
                  
                  291,310Other
      revenueUnrealized
      (loss) gain on financial derivative instruments
                  
                  
                  (18,251
                  )
                  
                  
                  (111,610
                  )
                  
                  
                  (129,861
                  )Other
      expensesDepletion,
      depreciation and accretion
                  
                  
                  259,545
                  
                  
                  
                  53,164
                  
                  
                  
                  312,709Goodwill
      impairment
                  
                  
                  -
                  
                  
                  
                  -
                  
                  
                  
                  -Interest
      on bank debt
                  
                  
                  2,465
                  
                  
                  
                  7,395
                  
                  
                  
                  9,860Interest
      and accretion on convertible debentures
                  
                  
                  5,489
                  
                  
                  
                  16,468
                  
                  
                  
                  21,957Unrealized
      foreign exchange loss (gain) and other
                  
                  
                  66
                  
                  
                  
                  4,095
                  
                  
                  
                  4,161Non-cash
      unit based compensation expense (recovery)
                  
                  
                  3,101
                  
                  
                  
                  3,225
                  
                  
                  
                  6,326Capital
      tax expense
                  
                  
                  2,313
                  
                  
                  
                  -
                  
                  
                  
                  2,313Current
      tax expense (recovery)
                  
                  
                  12
                  
                  
                  
                  225
                  
                  
                  
                  237Future
      income tax (recovery) expense
                  
                  
                  (71,682
                  )
                  
                  
                  (35,412
                  )
                  
                  
                  (107,094
                  )201,309
                  
                  
                  
                  49,160
                  
                  
                  
                  250,469Net
      (loss) income for the year
                  
                  $
                  (110,567
                  )
                  
                  $
                  21,547
                  
                  
                  $
                  (89,020
                  )
 
  
 
 As
      at and for the year ended December 31, 2009Provident
                  
                  
                  ProvidentUpstream
                  
                  
                  Midstream
                  
                  
                  TotalSelected
      balance sheet itemsCapital
      assetsProperty,
      plant and equipment net
                  
                  $
                  1,248,238
                  
                  
                  $
                  776,806
                  
                  
                  $
                  2,025,044Intangible
      assets
                  
                  
                  -
                  
                  
                  
                  132,478
                  
                  
                  
                  132,478Goodwill
                  
                  
                  -
                  
                  
                  
                  100,409
                  
                  
                  
                  100,409Capital
      expendituresCapital
      Expenditures
                  
                  
                  90,737
                  
                  
                  
                  36,632
                  
                  
                  
                  127,369Acquisitions
                  
                  
                  333
                  
                  
                  
                  18,500
                  
                  
                  
                  18,833Cash
      proceeds on sale of assets
                  
                  
                  305,720
                  
                  
                  
                  -
                  
                  
                  
                  305,720Working
      capitalAccounts
      receivable
                  
                  
                  37,582
                  
                  
                  
                  179,204
                  
                  
                  
                  216,786Petroleum
      product inventory
                  
                  
                  -
                  
                  
                  
                  37,261
                  
                  
                  
                  37,261Accounts
      payable and accrued liabilities
                  
                  
                  71,078
                  
                  
                  
                  150,339
                  
                  
                  
                  221,417Long-term
      debt - revolving term credit facilities
                  
                  
                  66,194
                  
                  
                  
                  198,582
                  
                  
                  
                  264,776Long-term
      debt - convertible debentures
                  
                  
                  60,121
                  
                  
                  
                  180,365
                  
                  
                  
                  240,486Asset
      retirement obligation
                  
                  
                  42,264
                  
                  
                  
                  19,200
                  
                  
                  
                  61,464Financial
      derivative instruments liability
                  
                  $
                  2,438
                  
                  
                  $
                  182,092
                  
                  
                  $
                  184,530
 
  
 
 Year
      ended December 31, 2008Provident
                  
                  
                  ProvidentUpstream
                  
                  
                  Midstream
      (1)
                  
                  
                  TotalRevenueGross
      production revenue
                  
                  $
                  681,336
                  
                  
                  $
                  -
                  
                  
                  $
                  681,336Royalties
                  
                  
                  (123,140
                  )
                  
                  
                  -
                  
                  
                  
                  (123,140
                  )Product
      sales and service revenue
                  
                  
                  -
                  
                  
                  
                  2,589,518
                  
                  
                  
                  2,589,518Realized
      gain (loss) on financial derivative instruments
                  
                  
                  (11,102
                  )
                  
                  
                  (118,917
                  )
                  
                  
                  (130,019
                  )547,094
                  
                  
                  
                  2,470,601
                  
                  
                  
                  3,017,695ExpensesCost
      of goods sold
                  
                  
                  -
                  
                  
                  
                  2,206,427
                  
                  
                  
                  2,206,427Production,
      operating and maintenance
                  
                  
                  138,173
                  
                  
                  
                  14,938
                  
                  
                  
                  153,111Transportation
                  
                  
                  16,320
                  
                  
                  
                  20,800
                  
                  
                  
                  37,120Foreign
      exchange loss (gain) and other
                  
                  
                  2,917
                  
                  
                  
                  (19,853
                  )
                  
                  
                  (16,936
                  )General
      and administrative
                  
                  
                  34,242
                  
                  
                  
                  33,845
                  
                  
                  
                  68,087Strategic
      review and restructuring
                  
                  
                  1,949
                  
                  
                  
                  1,683
                  
                  
                  
                  3,632193,601
                  
                  
                  
                  2,257,840
                  
                  
                  
                  2,451,441Earnings
      before interest, taxes, depletion, depreciation, accretion
    andother
      non-cash items
                  
                  
                  353,493
                  
                  
                  
                  212,761
                  
                  
                  
                  566,254Other
      revenueUnrealized
      (loss) gain on financial derivative instruments
                  
                  
                  30,230
                  
                  
                  
                  191,238
                  
                  
                  
                  221,468Other
      expensesDepletion,
      depreciation and accretion
                  
                  
                  304,909
                  
                  
                  
                  38,406
                  
                  
                  
                  343,315Goodwill
      impairment
                  
                  
                  416,890
                  
                  
                  
                  -
                  
                  
                  
                  416,890Interest
      on bank debt
                  
                  
                  9,022
                  
                  
                  
                  27,066
                  
                  
                  
                  36,088Interest
      and accretion on convertible debentures
                  
                  
                  4,986
                  
                  
                  
                  14,958
                  
                  
                  
                  19,944Unrealized
      foreign exchange loss (gain) and other
                  
                  
                  4,296
                  
                  
                  
                  (8,188
                  )
                  
                  
                  (3,892
                  )Non-cash
      unit based compensation expense (recovery)
                  
                  
                  (2,199
                  )
                  
                  
                  (1,918
                  )
                  
                  
                  (4,117
                  )Management
      charge - discontinued operations
                  
                  
                  (689
                  )
                  
                  
                  -
                  
                  
                  
                  (689
                  )Capital
      tax expense
                  
                  
                  3,109
                  
                  
                  
                  -
                  
                  
                  
                  3,109Current
      tax expense (recovery)
                  
                  
                  (212
                  )
                  
                  
                  (4,317
                  )
                  
                  
                  (4,529
                  )Future
      income tax (recovery) expense
                  
                  
                  (50,339
                  )
                  
                  
                  20,574
                  
                  
                  
                  (29,765
                  )689,773
                  
                  
                  
                  86,581
                  
                  
                  
                  776,354Net
      (loss) income for the year from continuing operations
                  
                  $
                  (306,050
                  )
                  
                  $
                  317,418
                  
                  
                  $
                  11,368Net
      income from discontinued operations (note 17)
                  
                  
                  
                  
                  
                  
                  
                  
                  
                  
                  146,024Net
      income for the year
                  
                  
                  
                  
                  
                  
                  
                  
                  
                  $
                  157,392(1)Included in the Midstream segment is product sales and service
      revenue of $307.9 million associated with U.S. operations.
  
 
 As
      at and for the year ended December 31, 2008Provident
                  
                  
                  ProvidentUpstream
                  
                  
                  Midstream
                  
                  
                  TotalSelected
      balance sheet itemsCapital
      assetsProperty,
      plant and equipment net
                  
                  $
                  1,731,331
                  
                  
                  $
                  749,172
                  
                  
                  $
                  2,480,503Intangible
      assets
                  
                  
                  -
                  
                  
                  
                  158,336
                  
                  
                  
                  158,336Goodwill
                  
                  
                  -
                  
                  
                  
                  100,409
                  
                  
                  
                  100,409Capital
      expendituresCapital
      Expenditures
                  
                  
                  209,147
                  
                  
                  
                  37,800
                  
                  
                  
                  246,947Acquisitions
                  
                  
                  25,843
                  
                  
                  
                  -
                  
                  
                  
                  25,843Cash
      proceeds on sale of assets
                  
                  
                  1,662
                  
                  
                  
                  -
                  
                  
                  
                  1,662Goodwill
      impairment
                  
                  
                  (416,890
                  )
                  
                  
                  -
                  
                  
                  
                  (416,890
                  )Working
      capitalAccounts
      receivable
                  
                  
                  60,839
                  
                  
                  
                  183,646
                  
                  
                  
                  244,485Petroleum
      product inventory
                  
                  
                  -
                  
                  
                  
                  46,160
                  
                  
                  
                  46,160Accounts
      payable and accrued liabilities
                  
                  
                  114,152
                  
                  
                  
                  129,879
                  
                  
                  
                  244,031Long-term
      debt - revolving term credit facilities
                  
                  
                  126,171
                  
                  
                  
                  378,514
                  
                  
                  
                  504,685Long-term
      debt - convertible debentures
                  
                  
                  59,031
                  
                  
                  
                  177,092
                  
                  
                  
                  236,123Asset
      retirement obligation
                  
                  
                  43,651
                  
                  
                  
                  15,781
                  
                  
                  
                  59,432Financial
      derivative instruments (asset) liability
                  
                  $
                  (15,806
                  )
                  
                  $
                  70,476
                  
                  
                  $
                  54,670
  
 
 21.
                Reconciliation
      of financial statements to United
States
 generally
accepted accounting principles (U.S. GAAP)
 
 The
consolidated financial statements have been prepared in accordance with
accounting principles generally accepted in Canada (“Canadian
GAAP”).  Any differences in accounting principles to U.S. GAAP as they
pertain to the accompanying financial statements are not material except as
described below.  All adjustments are measurement
differences.  Disclosure items are not
noted.
 
 
 Consolidated
      Statements of Earnings - U.S. GAAPFor
      the year ended December 31, (Cdn $000s)
                    
                    2009
                    
                    
                    2008Net
      (loss) income as reported
                    
                    $
                    (89,020
                    )
                    
                    $
                    157,392AdjustmentsDepletion,
      depreciation and accretion (a)
                    
                    
                    173,581
                    
                    
                    
                    79,558Depletion,
      depreciation and accretion - ceiling test impairment (a)
                    
                    
                    -
                    
                    
                    
                    (813,983
                    )Goodwill
      impairment (g)
                    
                    
                    -
                    
                    
                    
                    416,890Future
      income tax (expense) recovery (a) (b)
                    
                    
                    (54,706
                    )
                    
                    
                    180,161Gain
      on sale of discontinued operations
                    
                    
                    -
                    
                    
                    
                    (8,983
                    )Other
      adjustments to net income from discontinued operations
                    
                    
                    -
                    
                    
                    
                    2,976Net
      income – U.S. GAAP
                    
                    $
                    29,855
                    
                    
                    $
                    14,011Other
      comprehensive income
                    
                    
                    2,183
                    
                    
                    
                    67,005Comprehensive
      income
                    
                    
                    32,038
                    
                    
                    
                    81,016Net
      income (loss) from continuing operations per unit - basic and
      diluted
                    
                    $
                    0.11
                    
                    
                    $
                    (0.49
                    )Net
      income per unit - basic and diluted
                    
                    $
                    0.11
                    
                    
                    $
                    0.05
  Conde
      nsed Consolidate d Balance She etAs
      at December 31, (Cdn$ 000s)
                      
                      2009
                      
                      
                      
                      
                      
                      2008Canadian
                      
                      
                      
                      
                      
                      CanadianGAAP
                      
                      
                      U.S.
      GAAP
                      
                      
                      GAAP
                      
                      
                      U.S.
      GAAPAssetsDeferred
      financing charges (e)
                      
                      $
                      -
                      
                      
                      $
                      2,956
                      
                      
                      $
                      -
                      
                      
                      $
                      4,921Property,
      plant and equipment (a)
                      
                      
                      2,025,044
                      
                      
                      
                      916,683
                      
                      
                      
                      2,480,503
                      
                      
                      
                      1,198,561Goodwill
      (g)
                      
                      
                      100,409
                      
                      
                      
                      517,299
                      
                      
                      
                      100,409
                      
                      
                      
                      517,299Liabilities
      and unitholders’ equityCurrent
      portion of convertible debentures (d) (e)
                      
                      
                      -
                      
                      
                      
                      -
                      
                      
                      
                      24,871
                      
                      
                      
                      24,934Long-term
      debt - revolving term credit facilities (e)
                      
                      
                      264,776
                      
                      
                      
                      264,776
                      
                      
                      
                      504,685
                      
                      
                      
                      504,912Long-term
      debt - convertible debentures (d) (e)
                      
                      
                      240,486
                      
                      
                      
                      243,442
                      
                      
                      
                      236,123
                      
                      
                      
                      240,754Future
      income tax liability (asset) (a) (b)
                      
                      
                      162,665
                      
                      
                      
                      (119,168
                      )
                      
                      
                      267,807
                      
                      
                      
                      (68,733
                      )Units
      subject to redemption (f)
                      
                      
                      -
                      
                      
                      
                      1,855,405
                      
                      
                      
                      -
                      
                      
                      
                      1,381,352Unitholders'
      equity (f) (g)
                      
                      
                      1,381,399
                      
                      
                      
                      (883,644
                      )
                      
                      
                      1,636,347
                      
                      
                      
                      (273,517
                      )
 (a)
                Under
      the Canadian cost recovery ceiling test the recoverability of the oil and
      natural gas assets is tested by comparing the carrying value of the assets
      to the sum of the undiscounted proved reserve cash flows expected using
      future price estimates.  If the carrying value is not
      recoverable, the assets are written down to their 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 using discounted future net revenue from proved oil and
      natural gas reserves discounted at 10 percent.  For 2009, prices
      used in the U.S. GAAP ceiling tests are those that represent an average of
      the prices on the first day of each month in the calendar
      year.  For 2008, prices used in the U.S. GAAP ceiling test were
      those in effect at the end of 2008.  The amounts
      recorded
   
 
 for
      depletion and depreciation have been adjusted in the periods as a result
      of differences in write down amounts recorded pursuant to U.S. GAAP
      compared to Canadian GAAP.
 
 In
computing its consolidated net earnings for U.S. GAAP purposes, the Trust
recorded no additional depletion in 2009 (2008 – $814.0 million) and no
additional future income tax recovery (2008 - $214.3 million) as a result of the
application of the ceiling test.
 
 (b)
                The
      Canadian liability method of accounting for income taxes in CICA handbook
      Section 3465 “Income taxes” is similar to the requirements for U.S. GAAP,
      which requires the recognition of deferred tax assets and liabilities for
      the expected future tax consequences of events that have been recognized
      in Provident’s financial statements or tax returns.  Pursuant to
      U.S. GAAP, enacted tax rates are used to calculate future taxes, whereas
      Canadian GAAP uses substantively enacted rates.  In addition,
      U.S. GAAP uses 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.  U.S. GAAP 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
 
 (c)
                The
      consolidated statements of cash flows and operations and accumulated
      income are prepared in accordance with Canadian GAAP and conform in all
      material respects with U.S. GAAP except for that U.S. GAAP requires
      disclosure on the consolidated statement of operations when depreciation,
      depletion and amortization are excluded from cost of goods
      sold.  This disclosure has not been noted on the face of the
      consolidated statement of
operations.
 
 (d)
                In
      2009, the FASB issued FSP APB-14-1 that altered the way convertible
      debentures should be accounted for under U.S. GAAP.  The impact
      to Provident is that the balances recorded for long term debt –
      convertible debentures and unitholder’s equity no longer have a difference
      when compared to Canadian GAAP.  These changes were retroactive,
      therefore the comparative 2008 figures have been
  adjusted.
 
 (e)
                U.S.
      GAAP requires debt issue costs to be recorded as deferred
      charges.  Under Canadian GAAP, these costs are recorded against
      long-term debt.
 
 (f)
                Under
      U.S. GAAP, a redemption feature of equity instruments exercisable at the
      option of the holder requires that such equity be excluded from
      classification as permanent equity and be reported as temporary equity at
      the equity’s redemption value.  Changes in redemption value in
      the period (2009 - $445.9million
      increase; 2008 - $982.6 million decrease) are recorded to accumulated
      earnings.  Under Canadian GAAP, such equity instruments are
      considered to be permanent equity and are presented as unitholder’s
      equity.  The Trust’s units have a redemption feature, which
      qualify them to be considered under this
  guidance.
 
 (g)
                Under
      both Canadian and U.S. GAAP, goodwill is tested for impairment at least
      annually.  Both GAAP’s require that the fair value of the
      reporting unit be determined and compared to the book value of the
      reporting unit.  Under Canadian GAAP, this resulted in no
      impairment being recorded (2008 - $416.9 million).  Under U.S.
      GAAP the book value of the reporting unit was lower than the Canadian GAAP
      book value, primarily due to ceiling test impairments.  Using
      the lower book value under U.S. GAAP results in no goodwill impairment in
      both periods.
 
 
 Recent
      U.S. Accounting Pronouncements
 
 Non-controlling
interests in consolidated financial statements
 
 As of
January 1, 2009 Provident adopted ASC 810-10.  ASC 810-10 requires the
non-controlling ownership interests in subsidiaries held by parties other than
the parent be clearly presented in the consolidated balance sheet within equity,
but separate from the parent’s equity and the amount of consolidated net income
attributable to the parent and the non-controlling interest be clearly
identified and presented on the face of the consolidated
statement
  
 
 of
operations. Changes in the parent’s ownership interest should be accounted for
consistently as equity transactions. If a subsidiary is deconsolidated, any
retained non-controlling equity investment in the former subsidiary should be
initially recorded at fair value and the gain or loss on the deconsolidation of
the subsidiary is measured using the fair value of any non-controlling equity
investment rather than the carrying amount of the retained
investment..  The adoption of this statement has not had a material
impact on the Trust’s financial statements.
 
 Oil
and gas reporting disclosure
 
 During
2008, the United States Securities and Exchange Commission adopted revisions to
its oil and gas reporting disclosures contained in Regulation S-K and Regulation
S-X.  These revisions change the price basis for calculating reserves
from a single-day, year-end price to a monthly average price based on the first
day of each month.  These revisions have impacted the reserves in the
Trust’s accounting for depletion and its calculation of the ceiling test under
U.S. GAAP.
  ADDITIONAL
DISCLOSURE
  Certifications
and Disclosure Regarding Controls and Procedures.
  (a)
                  Certifications.  See
      Exhibits 99.1, 99.2, 99.3 and 99.4 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, 2009, an evaluation of the effectiveness of the
      registrant’s “disclosure controls and procedures” (as such term is defined
      in Rules 13a-15(e) and 15d-15(e) of the Securities Exchange Act of 1934,
      as amended (the “Exchange Act”)), was carried out by the management of
      Provident Energy Ltd., the administrator of the registrant, with the
      participation of the Chief Executive Officer (“CEO”) and Chief Financial
      Officer (“CFO”) of Provident Energy Ltd., who also perform such functions
      for the registrant.  Based upon that evaluation, the CEO and CFO
      have concluded that as of the end of that fiscal year, the registrant’s
      disclosure controls and procedures are effective to ensure that
      information required to be disclosed by the registrant in reports that it
      files or submits under the Exchange Act is (i) recorded, processed,
      summarized and reported within the time periods specified in Securities
      and Exchange Commission rules and forms and (ii) accumulated and
      communicated to the registrant’s management, including its principal
      executive officer and principal financial officer, to allow timely
      decisions regarding required
disclosure.
 
 It should
be noted that while the CEO and CFO believe that the registrant’s disclosure
controls and procedures provide a reasonable level of assurance that they are
effective, they do not expect that the registrant’s disclosure controls and
procedures or internal control over financial reporting will prevent all errors
and fraud.  A control system, no matter how well conceived or
operated, can provide only reasonable, not absolute, assurance that the
objectives of the control system are met.
 
 (c)
                  Management’s Annual
      Report on Internal Control Over Financial Reporting.  The
      required disclosure is included in the “Management Report” that
      accompanies the registrant’s Consolidated Financial Statements for the
      fiscal year ended December 31, 2009, filed as part of this Annual Report
      on Form 40-F.
 
 (d)
                  Attestation Report of
      the Registered Public Accounting Firm.  The required
      disclosure is included in the “Auditors’ Report” that accompanies the
      registrant’s Consolidated Financial Statements for the fiscal year ended
      December 31, 2009, filed as part of this Annual Report on Form
      40-F.
 
 (e)
                  Changes in Internal
      Control Over Financial Reporting.  During the fiscal year
      ended December 31, 2009, there were no changes in the registrant’s
      internal control over financial reporting that have materially affected,
      or are reasonably likely to materially affect, the registrant’s internal
      control over financial reporting.
 
  
 
 Notices Pursuant to Regulation
BTR.
 
 None.
 
 Audit
Committee Financial Expert.
 
 The
registrant’s board of directors has determined that Mike H. Shaikh, a member of
the registrant’s audit committee, qualifies as an “audit committee financial
expert” (as such term is defined in Form 40-F).  Mr. Shaikh is
“independent” as that term is defined in the rules of the New York Stock
Exchange.
 
 Code of Ethics.
 
 The
registrant has adopted a “code of ethics” (as that term is defined in Form 40-F)
that applies to its principal executive officer, principal financial officer,
principal accounting officer or controller, and persons performing similar
functions.
  The Code
of Ethics is available for viewing on the registrant’s website at
www.providentenergy.com.
  In
connection with the registrant’s listing on the New York Stock Exchange, the
Code of Ethics was amended in March 2006 to reflect the New York Stock
Exchange’s guidelines for codes of ethics.  Since the adoption of the
Code of Ethics, other than such amendment, there have not been any amendments to
the Code of Ethics or waivers, including implicit waivers, from any provision of
the Code of Ethics.
  Principal
Accountant Fees and Services.
  The
required tabular disclosure is included under the heading “Audit Committee
Information—External Auditor Service Fees”in the registrant’s
Annual Information Form, for the fiscal year ended December 31, 2009, filed as
part of this Annual Report on Form 40-F.
  Pre-Approval
Policies and Procedures.
  (a)
                  The
      required disclosure is included under the heading “Audit Committee
      Information—External Auditor Service Fees”in the
      registrant’s Annual Information Form for the fiscal year ended December
      31, 2009, filed as part of this Annual Report on Form
  40-F.
  (b)
                  Of
      the fees reported under the heading heading “Audit Committee
      Information—External Auditor Service Fees”in the
      registrant’s Annual Information Form for this fiscal year ended December
      31, 2009, filed as part of this Annual Report on Form 40-F, none of the
      fees billed by PricewaterhouseCoopers LLP were approved by the audit
      committee of the registrant pursuant to the de minimisexception
      provided by Section (c)(7)(i)(C) of Rule 2-01 of Regulation
      S-X.
  Off-Balance
Sheet Arrangements.
  The
registrant does not have any off-balance sheet financing arrangements that have
or are reasonably likely to have an effect on its results of operations or
financial condition.
  
 Tabular
Disclosure of Contractual Obligations.
  The
required disclosure is included under the heading “Contractual Obligations”in the registrant’s
Management’s Discussion and Analysis of Financial Condition and Results of
Operations for the fiscal year ended December 31, 2009, filed as part of this
Annual Report on Form 40-F.
  Identification
of the Audit Committee.
  The
registrant has a separately-designated standing audit committee established in
accordance with Section 3(a)(58)(A) of the Exchange Act.  The members
of the audit committee are:  Mike H. Shaikh, Hugh A. Fergusson and
Bruce R. Libin.
  Disclosure
Pursuant to the Requirements of the New York Stock Exchange.
 
 Presiding
Director at Meetings of Non-Management Directors
 
 The
registrant schedules regular executive sessions in which the registrant's
"non-management directors"(as that term is defined in the rules of the New York
Stock Exchange) meet without management participation.  Mr. John
Zaozirny serves as the presiding director (the "Presiding Director") at such
sessions.  Each of the registrant's non-management directors is
"independent"
as such term is used in the rules of the Toronto Stock Exchange.  The
Board of Directors of Provident Energy Ltd., the administrator of the
registrant, is responsible for determining whether or not each director is
independent.  In making this determination, the Board has adopted the
definition of "independence" as set out in Section 1.4 of National Instrument
52-110 Audit Committees ("NI-52-110").  In applying this definition,
the Board considers all relationships of the directors with the registrant and
Provident Energy Ltd., including business, family and other
relationships.  The Board of Directors also determines whether each
member of the Audit Committee of Provident Energy Ltd. is independent pursuant
to Sections 1.4 and 1.5 of NI 52-110 and Rule 10A-3 of the Exchange
Act.  The Board of Directors of Provident Energy Ltd. has not adopted
the director independence standards contained in Section 303A.02 of the NYSE's
Listed Company Manual.
 
 Communication
with Non-Management Directors
 
 Shareholders
may send communications to the registrant's non-management directors by writing
to the Presiding Director, c/o Lynn M. Rannelli, Assistant Corporate Secretary,
Provident Energy Ltd., 2100, 250 2nd
Steet S.W., Calgary, Alberta, Canada  T2P
0H3.  Communications will be referred to the Presiding Director for
appropriate action.  The status of all outstanding concerns addressed
to the Presiding Director will be reported to the board of directors as
appropriate.
  Corporate
Governance Guidelines
 
 According
to Section 303A.09 of the NYSE Listed Company Manual, a listed company must
adopt and disclose a set of corporate governance guidelines with respect to
specified topics.
  
 
 Such
guidelines are required to be posted on the listed company's
website.  The registrant operates under corporate governance
principles that are consistent with the requirements of Section 303A.09 of the
NYSE Listed Company Manual, many of which are described under the heading
"Corporate Governance" in the registrant's Information Circular in connection
with its 2010 Annual Meeting.  However, the registrant has not
codified its corporate governance principles into formal guidelines in order to
post them on its website.
 
 Board
Committee Mandates
 
 The
Mandates of the registrant's Audit Committee, Governance, Human Resources and
Compensation Committee, and Reserves , Operations and Environmental, Health and
Safety Committee are each available for viewing on the registrant's website at
www.providentenergy.com, and are available in print to any unitholder who
requests them.  Requests for copies of these documents should be made
by contacting: Lynn M. Rannelli, Assistant Corporate Secretary, Provident Energy
Ltd., 2100, 250 – 2 Street S.W., Calgary, Alberta, Canada T2P 0H3.
 Alternatively,
requests for these documents may be made by contacting the registrant's
Corporate Secretarial Department at (403) 296-2233 (Fax: (403)
205-3539).
  NYSE
Statement of Governance Differences
  As a
Canadian trust listed on the NYSE, the registrant is not required to comply with
most of the NYSE corporate governance standards, so long as it complies with
Canadian corporate governance practices.  In order to claim such an
exemption, however, the registrant must disclose the significant difference
between its corporate governance practices and those required to be followed by
United States domestic issuers under the NYSE’s corporate governance
standards.  The registrant has included a description of such
significant differences in corporate governance practices on its website, which
may be accessed at www.providentenergy.com.


UNDERTAKING
AND CONSENT TO SERVICE OF PROCESS


A.
              Undertaking.


The
registrant undertakes to make available, in person or by telephone,
representatives to respond to inquiries made by the Securities and Exchange
Commission (the “Commission”) staff, and to furnish promptly, when requested to
do so by the Commission staff, information relating to:  the
securities registered pursuant to Form   40-F; the securities in
relation to which the obligation to file an annual report on Form 40-F arises;
or transactions in said securities.




B.
            Consent
      to Service of Process.




The
Company has previously filed a Form F-X in connection with the class of
securities in relation to which the obligation to file this report
arises.




Any
change to the name or address of the agent for service of process of the
registrant shall be communicated promptly to the Securities and Exchange
Commission by an amendment to the Form F-X referencing the file number of the
relevant registration statement.




SIGNATURES




Pursuant
to the requirements of the Exchange Act, the registrant certifies that it meets
all of the requirements for filing on Form 40-F and has duly caused this annual
report to be signed on its behalf by the undersigned, thereunto duly authorized,
on March 18, 2010.








PROVIDENT ENERGY
      TRUST
                By:  Provident Energy Ltd.By:
              /s/ Thomas
      W. BuchananName:
      Thomas W. BuchananTitle:
      President and Chief Executive Officer












EXHIBIT
INDEX





Exhibit
            Description99.1
            Certification
      of Chief Executive Officer pursuant to Rule 13a-14(a) or 15d-14 of the
      Securities Exchange Act of 193499.2
            Certification
      of Chief Financial Officer pursuant to Rule 13a-14(a) or 15d-14 of the
      Securities Exchange Act of 193499.3
            Certification
      of Chief Executive Officer pursuant to 18 U.S.C. Section
    135099.4
            Certification
      of Chief Financial Officer pursuant to 18 U.S.C. Section
    135099.5
            Consent
      of PricewaterhouseCoopers LLP99.6
            Consent
      of McDaniel & Associates Consultants Ltd.99.7
            Consent
      of AJM Petroleum Consultants