Provident Energy Trust
TSX : PVE.UN
NYSE : PVX

Provident Energy Trust

March 12, 2009 00:15 ET

Provident Announces 2008 Annual and Fourth Quarter Results, 2008 Reserves Information and March Cash Distribution

CALGARY, ALBERTA--(Marketwire - March 12, 2009) - Provident Energy Trust (TSX:PVE.UN) (NYSE:PVX) -

All values are in Canadian dollars and conversions of natural gas volumes to barrels of oil equivalent (boe) are at 6:1 unless otherwise indicated.

Provident Energy Trust (Provident) (TSX:PVE.UN) (NYSE:PVX) today announced its 2008 fourth quarter interim and audited 2008 annual financial and operating results, 2008 reserves information and the March cash distribution of $0.06 per unit.

"2008 was an exceptional year for Provident, despite a very challenging fourth quarter." said Provident's President and Chief Executive Officer, Tom Buchanan. "Provident generated record funds flow from operations of $655 million and achieved a payout ratio of 58 percent. Provident reduced its bank debt by $419 million last year, strengthening the balance sheet at a time when financial flexibility is essential."

2008 Annual Highlights

- Consolidated funds flow from operations increased 40 percent to $655 million ($2.57 per unit) compared to $468 million ($2.04 per unit) in 2007.

- Provident's 2008 consolidated payout ratio was 58 percent, an improvement from 77 percent in 2007.

- Provident successfully divested its U.S. oil and gas production business resulting in after tax proceeds of approximately $458 million. This sale was the first step in a larger initiative to add flexibility to Provident's structure in order to better position the organization beyond 2011, when the new tax on trust distributions will be implemented.

- Canadian bank debt was reduced by 45 percent to $505 million in 2008. Provident has a total capacity of $1.125 billion in its revolving credit facility.

- Earnings before interest, taxes, depletion, depreciation, accretion and other non-cash items (EBITDA) from Provident Midstream was relatively stable at $213 million for 2008, down 6 percent from $226 million in 2007. Record margins in the first half of 2008 were offset by a decline in natural gas liquids (NGL) sale prices during the third and fourth quarters.

- Provident's Canadian Oil and Natural Gas Production division (Provident Upstream or COGP) generated funds flow from operations of $339 million ($1.33 per unit) in 2008 compared to $204 million ($0.89 per unit) in 2007. This record performance was the result of high commodity prices in the first half of the year coupled with strong operational results.

- Provident Upstream announced a new, internally generated medium crude oil play in the Pekisko formation in Northwest Alberta. Provident Upstream is developing this emerging resource play from a net land position of 95 sections (61,000 acres) using horizontal wells and multi-stage fracture technology.

- Provident Upstream production increased 4 percent to approximately 27,700 barrels of oil equivalent per day (boed) in 2008, up from approximately 26,500 boed in 2007. Production remains balanced at 51 percent natural gas and 49 percent crude oil and NGL.

- Provident successfully replaced 70 percent of 2008 Canadian production through internal development, drilling 87.4 net wells with a 99 percent success rate.

- Total proved plus probable oil and gas reserves at year-end decreased 3 percent to 97.8 million barrels of oil equivalent (mmboe) from 101.2 mmboe in 2007, while total proved plus probable reserve life index (RLI) was stable at 10 years.

- Total capital spending for the year was $209 million plus $22 million for acquisitions. Finding, development and acquisition (FD&A) costs including revisions and future development capital (FDC) were $35.28 per boe of proved plus probable reserves compared to $23.31 per boe in 2007. The three-year average FD&A costs including revisions and FDC were $24.34 per boe of proved plus probable reserves in 2008. The increase in 2008 FD&A costs reflect long term capital spending in relation to full-cycle development activities with $60 million invested in land, seismic and facilities that do not result in immediate reserve or production additions primarily in respect of the Pekisko oil play in Northwest Alberta.

2008 Fourth Quarter Summary

- Funds flow from continuing operations decreased 40 percent to $82 million ($0.32 per unit) in the quarter compared to $136 million ($0.72 per unit) in the fourth quarter of 2007 due primarily to weak commodity prices.

- Fourth quarter payout ratio was 95 percent, up from 57 percent in the fourth quarter of 2007.

- Provident Upstream production decreased 4 percent to approximately 26,850 boed in the fourth quarter from approximately 27,950 boed in the fourth quarter of 2007 due to a third-party pipeline outage, cold weather and natural production declines.

- Provident Midstream EBITDA was $38 million in the fourth quarter of 2008, down 58 percent from $89 million in the fourth quarter of 2007 due to lower NGL product margins, lower crude to gas ratio and 12 percent lower sales volumes partially offset by a realized gain from the commodity price risk management program of $16 million. Midstream results were impacted by a significant reduction in feedstock demand from the petro-chemical sector during the last half of the quarter. Demand has subsequently recovered during the first quarter of 2009.

- The fourth quarter net loss of $43 million includes the effect of a non-cash $417 million goodwill impairment charge largely offset by a non-cash unrealized gain on financial derivative instruments of $404 million. The goodwill impairment relates to the fair value of Provident Upstream being deemed lower than its respective carrying value reflecting the higher cost of debt and equity capital due to increasing economic uncertainty.

March 2009 Cash Distribution

The March cash distribution of $0.06 per unit is payable on April 15, 2009 and will be paid to unitholders of record as of March 24, 2009. The ex-distribution date will be March 20, 2009. The Trust's current annualized cash distribution rate is $0.72 per trust unit. Based on the current annualized cash distribution rate and the closing price on March 11, 2009 of $3.28, Provident's yield is approximately 22 percent.

For unitholders receiving their cash distribution in U.S. funds, the March 2009 cash distribution will be approximately US$0.05 per unit based on an exchange rate of 0.7808. The actual U.S. dollar cash distribution will depend on the Canadian/U.S. dollar exchange rate on the payment date and will be subject to applicable withholding taxes.

2009 Outlook

Continued price weakness and volatility in commodity markets is having a negative impact on the energy industry on a global scale. This market turmoil has resulted in reduced capital investment, activity levels and ongoing uncertainty in debt and equity markets in the first quarter of 2009. In the current environment, energy firms such as Provident will be challenged to generate cash flow comparable to levels achieved in recent years. Provident actively monitors commodity prices and market conditions on an ongoing basis and will continue to balance reinvestment of cash flow among capital expenditures, distributions and long term debt.

Provident Upstream has a 2009 capital budget of $88 million and plans to drill a total of 23.8 net wells. Approximately $36 million is being directed towards development of the Pekisko medium oil play in Northwest Alberta. Three new Pekisko wells have been drilled and surface facilities are now being installed that will enable year round production from four of the five Pekisko wells beginning in the second quarter of 2009. Approximately $19 million is allocated to the implementation of the first phase of the waterflood project in Dixonville. The remaining $33 million is budgeted for development initiatives in other areas. 2009 production is expected to average between 23,500 and 25,000 barrels of oil equivalent per day (boed). Subject to pricing assumptions, royalty rates are expected to fall this year to approximately 17 percent including the impact of the new Alberta royalty framework. Operating costs are expected to remain relatively stable in the first half of 2009, but should begin to moderate in the latter half of the year as labour, service and material costs deflate as development activity slows.

Provident Midstream has a 2009 capital budget of approximately $27 million. This budget will be used, in part, to complete two 500,000 barrel condensate caverns which will enter service at the Redwater facility in the summer of 2009. Work also continues on a third cavern of equal size that is expected to be complete in 2011. Upon completion of these caverns, Provident will own 6.6 million barrels of underground product storage at Redwater. A portion of the 2009 capital budget will be directed towards certain facility optimization and debottlenecking initiatives while approximately $6 million will be used for normal course facility maintenance. Provident is also allocating a portion of its 2009 capital budget towards the initial phases of a project to construct a depropanizer facility located in Michigan. The Michigan depropanizer is one of several options under consideration to mitigate the financial impact of the potential 6,000 barrels per day curtailment of NGL fractionation capacity at Sarnia which would take effect April 1, 2009, contingent on ongoing contractual negotiations with the facility owner.

NGL margins have strengthened in the first quarter of 2009 compared to the fourth quarter of 2008. This improvement is the result of substantially higher sale prices for propane and butane due to strong winter demand coupled with a lower cost of sales as the majority of the high cost inventory accumulated during 2008 has been depleted.

Provident Energy Trust is a Calgary-based, open-ended energy income trust that owns and manages an oil and gas production business and a natural gas liquids midstream services and marketing business. Provident's energy portfolio is located in some of the most stable and predictable producing regions in Western Canada. Provident provides monthly cash distributions to its unitholders and trades on the Toronto Stock Exchange and the New York Stock Exchange under the symbols PVE.UN and PVX, respectively.

This document contains certain forward-looking statements concerning Provident, as well as other expectations, plans, goals, objectives, information or statements about future events, conditions, results of operations or performance that may constitute "forward-looking statements" or "forward-looking information" under applicable securities legislation. Such statements or information involve substantial known and unknown risks and uncertainties, certain of which are beyond Provident's control, including the impact of general economic conditions in Canada and the United States, industry conditions, changes in laws and regulations including the adoption of new environmental laws and regulations and changes in how they are interpreted and enforced, increased competition, the lack of availability of qualified personnel or management, pipeline design and construction, fluctuations in commodity prices, foreign exchange or interest rates, stock market volatility and obtaining required approvals of regulatory authorities.

Such forward-looking statements or information are based on a number of assumptions which may prove to be incorrect. In addition to other assumptions identified in this news release, assumptions have been made regarding, among other things, commodity prices, operating conditions, capital and other expenditures, and project development activities.

Although Provident believes that the expectations reflected in such forward-looking statements or information are reasonable, undue reliance should not be placed on forward-looking statements because Provident can give no assurance that such expectations will prove to be correct. Forward-looking statements or information are based on current expectations, estimates and projections that involve a number of risks and uncertainties which could cause actual results to differ materially from those anticipated by Provident and described in the forward-looking statements or information.

The forward-looking statements or information contained in this news release are made as of the date hereof and Provident undertakes no obligation to update publicly or revise any forward-looking statements or information, whether as a result of new information, future events or otherwise unless so required by applicable securities laws. The forward-looking statements or information contained in this news release are expressly qualified by this cautionary statement.



Consolidated financial highlights

Consolidated
($ 000s
except per Three months ended Year ended
unit data) December 31, December 31,
----------------------------------------------------------------------------
% %
2008 2007 Change 2008 2007 Change
----------------------------------------------------------------------------

Revenue (net
of royalties
and financial
derivative
instruments)
from continuing
operations $1,019,320 $521,648 95 $3,239,163 $2,038,515 59
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Funds flow
from
Provident
Upstream
operations
(1) $ 47,187 $ 58,667 (20) $ 338,640 $ 204,252 66
Funds flow
from
Provident
Midstream
operations(1) 34,592 77,109 (55) 178,982 178,432 -
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Funds flow
from
continuing
operations 81,779 135,776 (40) 517,622 382,684 35
Funds flow
from
discontinued
operations
(USOGP) (1)
(2) (3) - 41,787 (100) 137,535 85,571 61
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Total funds
flow from
operations
(1) $ 81,779 $177,563 (54) $ 655,157 $ 468,255 40
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Per weighted
average unit
- basic and
diluted (4) $ 0.32 $ 0.72 (56) $ 2.57 $ 2.04 26
Distributions
to
unitholders $ 77,324 $ 89,063 (13) $ 352,291 $ 333,352 6
Per unit $ 0.30 $ 0.36 (17) $ 1.38 $ 1.44 (4)
Percent of
funds flow
from
operations
paid out as
declared
distributions (5) 95% 57% 67 58% 77% (25)
Net (loss)
income $ (43,248) $ 68,545 - $ 157,392 $ 30,434 417
Per weighted
average unit
- basic and
diluted (4) $ (0.17) $ 0.28 - $ 0.62 $ 0.13 377
Capital
expenditures
(continuing
operations) $ 54,903 $ 75,213 (27) $ 246,947 $ 178,113 39
Capitol
Energy
acquisition $ - $ (355) $ - $ 467,495
Triwest
Energy
acquisition $ - $ 78,877 $ - $ 78,877
Oil and gas
property
acquisitions,
net
(continuing
operations) $ 4,594 $ 1,481 $ 24,181 $ 13,050
Proceeds on
sale of
discontinued
operations,
net of tax $ 19,044 $ - $ 457,906 $ -
Weighted
average trust
units
outstanding
(000s)
- Basic and
diluted (4) 257,526 247,052 4 255,177 229,939 11
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Consolidated
----------------------------------------------------------------------------
As at December 31,
($ 000s) 2008 2007 % Change
----------------------------------------------------------------------------
Capitalization
Long-term debt (including current portion) $ 765,679 $1,199,634 (36)
Unitholders' equity $1,636,347 $1,708,665 (4)
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(1) Represents cash flow from operations before changes in working capital
and site restoration expenditures.
(2) Effective in the first quarter of 2008, Provident's USOGP business is
accounted for as discontinued operations (see note 15 of consolidated
financial statements).
(3) Prior to the sale of USOGP, Provident owned approximately 22 per cent of
the MLP and 96 per cent of BreitBurn. In accordance with generally
accepted accounting principles (GAAP) in Canada and the United States,
these investments were consolidated into Provident's results. On a
proportionate basis, Provident's share of funds flow from operations
relating to discontinued operations (USOGP) for the three months and
year ended December 31, 2008 was nil and $57.9 million, respectively.
(4) Includes dilutive impact of unit options and convertible debentures.
(5) Calculated as distributions to unitholders divided by funds flow from
operations less distributions to non-controlling interests of $51.4
million for the year ended December 31, 2008 and nil for the quarter
(2007 - $35.8 million and $22.1 million, respectively).


Operational highlights
Three months ended Year ended
December 31, December 31,
----------------------------------------------------------------------------
% %
2008 2007 Change 2008 2007 Change
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Oil and Gas
Production
Daily
production -
Provident
Upstream
(continuing
operations)
Crude oil (bpd) 12,307 11,252 9 12,473 9,797 27
Natural gas
liquids (bpd) 1,134 1,277 (11) 1,203 1,316 (9)
Natural gas
(mcfpd) 80,450 92,584 (13) 84,039 92,378 (9)
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Provident
Upstream oil
equivalent
(boed) (1) 26,849 27,960 (4) 27,683 26,509 4
USOGP
(discontinued
operations) oil
equivalent
(boed) (1) - 20,255 (100) 12,003 12,124 (1)
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Consolidated
oil equivalent
(boed) (1) 26,849 48,215 (44) 39,686 38,633 3
----------------------------------------------------------------------------

Average
realized price
from continuing
operations
(before
realized
financial
derivative
instruments)
Crude oil blend
($/bbl) $ 47.33 $ 61.75 (23) $ 82.79 $ 56.74 46
Natural gas
liquids
($/bbl) $ 47.64 $ 63.63 (25) $ 76.88 $ 55.07 40
Natural gas
($/mcf) $ 6.63 $ 6.08 9 $ 8.23 $ 6.42 28
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Oil equivalent
($/boe) (1) $ 43.58 $ 47.88 (9) $ 65.64 $ 46.09 42
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Field netback
from continuing
operations
(before
realized
financial
derivative
instruments)
($/boe) $ 21.21 $ 27.10 (22) $ 39.85 $ 25.47 56
Field netback
from continuing
operations
(including
realized
financial
derivative
instruments)
($/boe) $ 24.54 $ 27.29 (10) $ 38.75 $ 25.65 51
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Midstream
Provident
Midstream NGL
sales volumes
(bpd) 120,222 135,981 (12) 119,649 120,785 (1)
EBITDA (000s)
(2) $ 37,666 $ 89,423 (58) $212,761 $225,675 (6)
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(1) Provident reports oil equivalent production converting natural gas to
oil on a 6:1 basis.
(2) EBITDA is earnings before interest, taxes, depletion, depreciation,
accretion and other non-cash items. See "Reconciliation of non-GAAP
measures".


Reserves Information

Oil and Natural Gas Reserves

Provident's reserves were evaluated by McDaniel & Associates Consultants Ltd. (McDaniel) and by AJM Petroleum Consultants (AJM) in accordance with the Canadian Securities Administrators' National Instrument 51-101 Standards of Disclosure for Oil and Gas Activities (NI 51-101). McDaniel evaluated all of Provident's Canadian oil and natural gas properties, except the Northwest Alberta properties which were evaluated by AJM. McDaniel and AJM are independent qualified reserves evaluators appointed pursuant to NI 51-101. Additional information pertaining to NI 51-101 and some of the key reserves definitions are provided at the conclusion of the Reserves section. Additional details on the Trust's reserves can be found in Form NI 51-101 F1.

On June 17, 2008 Provident announced that it had sold a portion of its U.S. oil and gas business consisting of its 22 percent interest in BreitBurn Energy Partners L.P. ("BreitBurn MLP") and its 96 percent interest in BreitBurn GP LLC ("BreitBurn GP"). On July 30, 2008 Provident announced that it had reached an agreement to sell the remaining portion of its U.S. oil and gas business, BreitBurn Energy Company L.P. ("BreitBurn"). Provident subsequently announced the close of the sale of BreitBurn on August 26, 2008. After the transactions all of Provident's reserves are located in Canada.

Provident's oil and natural gas reserves and present value of estimated future cash flows based on forecast prices and costs as of December 31, 2008 using the McDaniel January 1, 2009 price forecast are summarized in the following tables. Reserves are presented on a Gross (working interest) and Net basis (refer to the notes under the tables and to the Definitions at the end of the Reserves section for explanations of company share, working interest, gross and net). In October 2007, the Alberta government announced its intention to amend crown royalties effective January 1, 2009. Provident Upstream (COGP) reserves as presented herein are based on the Alberta New Royalty Framework including the Transitional Royalties that were announced in November 2008.



Reserves as of December 31, 2008(a)

Using McDaniel Price Forecast

Gross Reserves(b)
----------------------------------------------------------------------------
Light &
Medium Heavy
Crude Crude Total Natural Total
Oil(d) Oil(d) Oil NGL Gas Boe
(Mbbl) (Mbbl) (Mbbl) (Mbbl) (MMcf) (Mboe)
----------------------------------------------------------------------------
Proved Reserves
Producing 18,075 3,754 21,829 1,994 154,455 49,565
Non-Producing 199 195 394 108 17,392 3,400
Undeveloped 1,586 1,145 2,731 161 20,705 6,342
----------------------------------------------------------------------------
Total Proved 19,859 5,094 24,953 2,262 192,552 59,307
Probable 19,400 3,982 23,382 924 82,399 38,039
----------------------------------------------------------------------------
TOTAL Proved
plus Probable 39,259 9,076 48,335 3,186 274,951 97,346
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Net Reserves(c)
----------------------------------------------------------------------------
Light &
Medium Heavy
Crude Crude Total Natural Total
Oil Oil Oil NGL Gas Boe
(Mbbl) (Mbbl) (Mbbl) (Mbbl) (MMcf) (Mboe)
----------------------------------------------------------------------------
Proved Reserves
Producing 13,934 3,122 17,056 1,402 130,200 40,158
Non-Producing 143 164 307 72 11,743 2,336
Undeveloped 1,402 844 2,245 102 17,242 5,221
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Total Proved 15,479 4,129 19,609 1,576 159,185 47,715
Probable 12,723 3,084 15,806 648 66,915 27,607
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TOTAL Proved
plus Probable 28,202 7,213 35,415 2,223 226,100 75,322
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Notes:
(a) Tables may not add due to rounding
(b) Gross Reserves are Provident's working interest (operated or
non-operated) share before deduction of royalties and without including
any royalty interests of Provident.
(c) Net Reserves are Provident's working interest (operated or
non-operated) share after deduction of royalty obligations, plus
Provident's royalty interests in reserves.
(d) The definition of light, medium and heavy oil for Canada is consistent
with the royalty regime of each Province. Heavy Oil within the province
of Alberta includes oil defined as heavy and ultra-heavy in accordance
with the New Royalty Framework, which came into effect on January 1,
2009.


Present Value of Reserves as of December 31, 2008(a)

Using McDaniel Price Forecast

The present value of estimated future cash flows based on forecast prices and costs of Provident's oil and natural gas reserves are summarized in the following tables. The impact of Federal income tax changes that were enacted during 2007 have been incorporated in the table showing After Tax values. According to these tax laws the Trust is expected to be taxable beginning January 1, 2011. Tax pools held by the Trust will defer the impact of these changes such that only the values of total proved and proved plus probable reserves will be affected.



Present Value ($000's) Before Tax Discounted at
----------------------------------------------------------------------------
0% 8% 10% 15% 20%
----------------------------------------------------------------------------
Proved Reserves
Producing $1,422,130 $1,019,045 $ 951,406 $ 817,979 $ 720,111
Non-Producing 53,423 46,336 42,713 34,967 29,138
Undeveloped 107,880 44,420 34,440 15,380 2,119
----------------------------------------------------------------------------
Total Proved 1,583,434 1,109,801 1,028,558 868,325 751,368
Probable 1,463,803 577,184 492,757 355,425 273,576
----------------------------------------------------------------------------
TOTAL Proved
plus Probable $3,047,237 $1,686,985 $1,521,315 $ 1,223,751 $ 1,024,943
----------------------------------------------------------------------------
----------------------------------------------------------------------------



Present Value ($000's) After Tax(b) Discounted at
----------------------------------------------------------------------------
0% 8% 10% 15% 20%
----------------------------------------------------------------------------
Proved Reserves
Producing $1,422,130 $1,019,045 $ 951,406 $ 817,979 $ 720,111
Non-Producing 53,423 46,336 42,713 34,967 29,138
Undeveloped 99,727 42,459 33,040 14,759 1,833
----------------------------------------------------------------------------
Total Proved 1,575,281 1,107,840 1,027,159 867,705 751,082
Probable 1,135,835 466,976 403,727 300,068 237,062
----------------------------------------------------------------------------
TOTAL Proved
plus Probable $2,711,116 $1,574,815 $1,430,886 $ 1,167,773 $ 988,144
----------------------------------------------------------------------------
----------------------------------------------------------------------------

Notes:
(a) Tables may not add due to rounding
(b) After tax values include the impact of Canadian Federal and Provincial
Income taxes beginning January 1, 2011.


COGP Oil and Natural Gas Reserves

Total COGP proved plus probable reserves decreased from 101,239 Mboe as of December 31, 2007 to 97,763 Mboe as of December 31, 2008. After accounting for production, COGP total proved reserves increased by 4,858 Mboe while proved plus probable reserves increased by 6,657 Mboe. Internal development activities in Western Canada were successful in replacing 70 percent of production. Drilling additions include 1,361 Mboe total proved and 2,695 Mboe proved plus probable reserves for the emerging Pekisko oil play in Northwest Alberta. Acquisitions of partner interests in Southeast Saskatchewan plus various smaller acquisitions added proved plus probable reserves of 1,047 Mboe. Drilling and tie-in activity, which was primarily focused in the Dixonville and Rainbow areas of Alberta and the Steelman area of Southeast Saskatchewan, resulted in the transfer of 3,684 Mboe to proved developed producing and 1,081 Mboe from probable to proved.



COGP Reconciliation Summary(a)
Proved Developed Producing


Light &
Medium Heavy
Crude Crude Total Total
Company Share Oil(d) Oil(d) Crude Oil Gas NGL BOE
(WI +RI)(b) Mbbl Mbbl Mbbl MMcf Mbbl Mboe
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Balance at
December 31,
2007(d) 16,589 3,608 20,198 173,267 2,247 51,323
Production (3,724) (841) (4,565) (30,758) (440) (10,132)
Drilling Activity
Exploration
Discoveries 0 0 0 0 0 0
Drilling
Extensions 349 462 811 2,530 14 1,246
Recompletion 241 741 982 4,652 22 1,779
Transfer 3,049 189 3,237 2,651 5 3,684
Acquisition 445 0 445 266 1 490
Divestiture 0 0 0 0 0 0
Economic Factors 16 3 19 1,862 10 339
Technical
Revisions 1,153 (404) 749 1,044 161 1,084
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Balance at
December 31,
2008 18,117 3,759 21,875 155,514 2,019 49,813
----------------------------------------------------------------------------
----------------------------------------------------------------------------
WI Share (c)
Balance at
December 31,
2008 18,075 3,754 21,829 154,455 1,994 49,565
----------------------------------------------------------------------------
----------------------------------------------------------------------------



COGP Reconciliation Summary(a)
Total Proved


Light &
Medium Heavy
Crude Crude Total Total
Company Share Oil(d) Oil(d) Crude Oil Gas NGL BOE
(WI +RI)(b) Mbbl Mbbl Mbbl MMcf Mbbl Mboe
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Balance at
December 31,
2007 22,896 4,412 27,308 210,879 2,415 64,869
Production (3,724) (841) (4,565) (30,758) (440) (10,132)
Drilling Activity
Exploration
Discoveries 0 0 0 0 0 0
Drilling
Extensions 366 1,362 1,728 5,527 65 2,714
Recompletion 261 741 1,002 5,430 36 1,943
Transfer 914 68 982 589 0 1,081
Acquisition 662 0 662 277 1 709
Divestiture 0 0 0 0 0 0
Economic Factors 16 3 19 2,090 11 378
Technical
Revisions (1,486) (646) (2,132) (240) 207 (1,965)
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Balance at
December 31,
2008 19,905 5,099 25,004 193,792 2,293 59,596
----------------------------------------------------------------------------
----------------------------------------------------------------------------
WI Share (c)
Balance at
December 31,
2008 19,859 5,094 24,953 192,552 2,262 59,307
----------------------------------------------------------------------------
----------------------------------------------------------------------------



COGP Reconciliation Summary(a)
Total Proved plus Probable


Light &
Medium Heavy
Crude Crude Total Total
Company Share Oil(d) Oil(d) Crude Oil Gas NGL BOE
(WI +RI)(b) Mbbl Mbbl Mbbl MMcf Mbbl Mboe
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Balance at
December 31,
2007 42,007 7,133 49,140 292,763 3,305 101,239
Production (3,724) (841) (4,565) (30,758) (440) (10,132)
Drilling Activity
Exploration
Discoveries 0 0 0 0 0 0
Drilling
Extensions 586 2,695 3,281 7,884 96 4,691
Recompletion 345 981 1,326 5,993 57 2,382
Transfer 0 0 0 0 0 0
Acquisition 968 0 968 463 1 1,047
Divestiture 0 0 0 0 0 0
Economic Factors 26 4 30 2,854 16 522
Technical
Revisions (884) (890) (1,773) (2,426) 194 (1,984)
----------------------------------------------------------------------------
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Balance at
December 31,
2008 39,324 9,083 48,407 276,771 3,228 97,763
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WI Share (c)
Balance at
December 31,
2008 39,259 9,076 48,335 274,951 3,186 97,346
----------------------------------------------------------------------------
----------------------------------------------------------------------------

Notes:
(a) Tables may not add due to rounding
(b) Company share includes working interest (WI) and royalty interest (RI)
volumes.
(c) WI share includes the Company's working interests only, and excludes
volumes associated with royalties.
(d) The definition of light, medium and heavy oil for Canada is consistent
with the royalty regime of each Province. Heavy Oil within the province
of Alberta includes oil defined as heavy and ultra-heavy in accordance
with the New Royalty Framework, which came into effect on January 1,
2009.


On a Consolidated basis, Proved plus Probable reserves decreased from 322,827 Mboe as of December 31, 2007 to 97,763 Mboe as of December 31, 2008. The majority of this decrease is due to the sale of the U.S. assets. Reconciliation tables that provide the details of Provident's consolidated reserve activity for each reserve category for the year ended December 31, 2008 are provided in Form 51-101 F1.

Price Forecast Summary

The following table summarizes the McDaniel January 1, 2009 price forecast used in evaluating Provident's reserves under forecast price and cost assumptions.



WTI Crude
at Light, Sweet Alberta
Exchange Cushing Crude Bow River Heavy Oil at Alberta AECO
Rate Oklahoma at Edmonton Hardisty Hardisty Gas Spot Price
Year US$/Cdn$ US$/bbl Cdn$/bbl Cdn$/bbl Cdn$/bbl Cdn$/Mmbtu
----------------------------------------------------------------------------
2009 0.850 60.00 69.60 54.80 47.00 7.40
2010 0.850 71.40 83.00 65.30 56.10 8.00
2011 0.900 83.20 91.40 72.00 61.80 8.45
2012 0.950 90.20 93.90 73.90 64.00 8.80
2013 1.000 97.40 96.30 75.90 65.60 9.05
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----------------------------------------------------------------------------


Reserve Life Index (RLI)

Provident's proved plus probable RLI as of December 31, 2008, which was stable at 10.0 years, was determined by applying the average actual production rates for the last quarter of 2008 to reserve volumes for each reserve category from the McDaniel and AJM evaluations as of December 31, 2008. The following table illustrates the reserve life index for COGP for the various product and reserve categories as of December 31, 2008 and for the prior five years.



COGP Reserve Life Index
Company share (WI + RI)


RLI (years) as of December 31
Total Crude Oil 2008 2007 2006 2005 2004 2003
----------------------------------------------------------------------------
Proved Producing 4.9 4.6 4.4 3.9 3.3 3.0
Total Proved 5.6 6.2 4.8 4.3 4.0 3.9
Proved plus Probable 10.8 11.2 6.8 5.8 5.4 5.4


Natural Gas & NGL
----------------------------------------------------------------------------
Proved Producing 5.3 5.2 5.0 4.4 4.1 4.4
Total Proved 6.5 6.3 6.0 5.4 4.9 4.9
Proved plus Probable 9.3 8.7 8.3 7.1 6.4 6.1


Oil Equivalent (6:1)
----------------------------------------------------------------------------
Proved Producing 5.1 4.9 4.8 4.2 3.7 3.7
Total Proved 6.1 6.2 5.6 5.0 4.5 4.4
Proved plus Probable 10.0 9.7 7.8 6.5 5.9 5.7


Finding, Development and Acquisition Costs

Finding and development costs (F&D) include all costs to develop reserves, including land and seismic costs. The methodology used to calculate F&D costs under NI 51-101 requires that F&D costs incorporate changes in future development capital (FDC) required to bring non-producing and undeveloped reserves to production. This capital, which is included in the reserves evaluations, is part of the ongoing development process necessary to bring production on stream and generate cash flow. Provident's FDC has increased over the past several years with the acquisition of undeveloped reserves and with the 2008 addition of the emerging Pekisko oil play. To provide clarity in the true costs to find and develop reserves, Provident does not include the FDC associated with acquisitions in the F&D costs. However, since FDC is a component of the cost of acquiring reserves Provident does include the FDC associated with acquisitions in the FD&A costs.

Drilling and recompletion activity during 2008 made a significant contribution with total proved additions of 4,657 Mboe and proved plus probable additions of 7,073 Mboe. Provident's focus is development and exploitation of reserves and promotes between reserve categories. As a result of capital expenditures during 2008, Provident promoted 3,684 Mboe of reserves into the proved developed producing category. The associated capital and any changes to it have been included in the F&D calculations. Continued development of the Dixonville Montney C pool during 2008 was a significant recipient of capital expenditures resulting in transfers during 2008. Further development drilling and waterflood expansion of the Montney C pool is planned for the next several years.

The success of the Pekisko Oil play in 2008 led to proved reserve additions of 1,361 Mboe and proved plus probable additions of 2,695 Mboe for two producing Pekisko oil wells plus offsetting undeveloped locations. Expenditures for land and seismic activity associated with this play are included in the 2008 capital expenditures plus future development capital is included in the reserves for drilling, completion, facility and infrastructure costs.

The aggregate of the development costs incurred in the most recent financial year and the change during that year in estimated future development costs generally will not reflect total finding and development costs related to reserve additions for that year. A three-year average of F&D costs is a better reflection of full cycle economics and is therefore a more appropriate view of the cost of reserve additions. The three-year average FD&A cost does include the change in FDC, including acquisitions, over the three year period. Acquisition costs include the cash cost of acquiring reserves and the fair value of liabilities assumed. NI 51-101 does not contemplate nor define acquisition costs. Provident has included goodwill on the corporate acquisitions as part of the purchase price allocation, and therefore forms part of the costs of acquiring the reserves.

Finding, development and acquisition (FD&A) costs including revisions and future development capital (FDC) were $35.28 per boe of proved plus probable reserves compared to $23.31 per boe in 2007. The three-year average FD&A costs including revisions and FDC were $24.34 per boe of proved plus probable reserves in 2008. The increase in 2008 FD&A costs reflect a bias towards long term capital spending in relation to full-cycle development activities with $60 million (of $231 million) invested in land, seismic and facilities that do not result in immediate reserve or production additions. COGP is building a long-term play for Pekisko Oil and investing in the long-term waterflood project at Dixonville.

Details of the F&D cost calculations and results are provided in the following tables.

The following table presents the details of the 2008 Finding, Development and Acquisition cost calculations and illustrates the impact of including the change in future development capital in the calculation.



COGP 2008 Finding, Development and Acquisition Costs

Reserve
Additions
including F&D
Capital Revisions Costs
($000s) Mboe(a) $/boe(b)
----------------------------------------------------------------------------
Finding and Development Costs

Total Proved
-------------
Capital Expenditures (1) $ 205,429 4,149 $ 49.51
Change in FDC(2) (620)
-----------
Total F&D including change in FDC $ 204,809 4,149 $ 49.36

Proved plus Probable
---------------------
Capital Expenditures (1) $ 205,429 5,610 $ 36.62
Change in FDC(2) (2,080)
-----------
Total F&D including change in FDC $ 203,349 5,610 $ 36.25

Finding, Development and Acquisition Costs

Total Proved
-------------
Capital Expenditures and Acquisition
Costs (1) $ 231,161 4,858 $ 47.58
Change in FDC(2) 3,800
-----------
Total FD&A including change in FDC $ 234,961 4,858 $ 48.36

Proved plus Probable
---------------------
Capital Expenditures and Acquisition
Costs (1) $ 231,161 6,657 $ 34.73
Change in FDC(2) 3,700
-----------
Total FD&A including change in FDC $ 234,861 6,657 $ 35.28


Details of Capital and FDC
----------------------------
(1) Total F&D Costs ($000s)
2008 Oil and Gas Capital
Expenditures $ 205,429
Property Acquisitions (net of
dispositions) 25,732
Corporate Acquisitions -
----------
Total Oil and Gas FD&A costs $ 231,161
-----------------------------------------------------------------------

(2) Change in Future Development Costs ($000s) Proved
Total plus
Proved Probable
------------------------------
FDC as of 2008-12-31 $ 165,400 $ 221,800
FDC as of 2007-12-31 161,600 218,100
------------------------------
Change in FDC for FD&A Calculation $ 3,800 $ 3,700
FDC of Acquired Properties 4,420 5,780
------------------------------
Change in FDC for F&D Calculation $ (620) $ (2,080)


The following table presents the details of the three-year average Finding, Development and Acquisition cost calculations and illustrates the impact of including the change in future development capital in the calculation.



COGP Three-year Finding, Development and Acquisition Costs

Reserve
Additions
including F&D
Capital Revisions Costs
($000s) Mboe(a) $/boe(b)
----------------------------------------------------------------------------
Finding and Development Costs

Total Proved
-------------
Capital Expenditures (1) $ 355,064 10,789 $ 32.91
Change in FDC(2) (4,121)
-------------
Total F&D including change in FDC $ 350,944 10,789 $ 32.53

Proved plus Probable
---------------------
Capital Expenditures (1) $ 355,064 11,753 $ 30.21
Change in FDC(2) (2,839)
-------------
Total F&D including change in FDC $ 352,225 11,753 $ 29.97

Finding, Development and Acquisition
Costs

Total Proved
-------------
Capital Expenditures and Acquisition
Costs (1) $ 1,523,076 45,528 $ 33.45
Change in FDC(2) 140,700
-------------
Total FD&A including change in FDC $ 1,663,777 45,528 $ 36.54

Proved plus Probable
---------------------
Capital Expenditures and Acquisition
Costs (1) $ 1,523,076 70,269 $ 21.68
Change in FDC(2) 187,271
-------------
Total FD&A including change in FDC $ 1,710,347 70,269 $ 24.34


Details of Capital and FDC
---------------------------
(1) Total F&D Costs ($000s)
Oil and Gas Capital Expenditures $ 355,064
Property Acquisitions (net of
dispositions) 571,769
Corporate Acquisitions 596,243
-------------
Total Oil and Gas FD&A costs $ 1,523,076
---------------------------------------------------------------------


(2) Change in Future Development Costs ($000s) Proved
Total plus
Proved Probable
------------------------------
FDC as of 2008-12-31 $ 165,400 $ 221,800
FDC as of 2005-12-31 24,700 34,529
------------------------------
Change in FDC for FD&A Calculation $ 140,700 $ 187,271
FDC of Acquired Properties 144,821 190,110
------------------------------
Change in FDC for F&D Calculation $ (4,121) $ (2,839)


The following table presents finding and development costs and finding, development and acquisition costs for proved and proved plus probable reserves for the year ending December 31, 2008 and for the prior two years. The aggregate of the exploration and development costs incurred in the most recent financial year and the change during that year in estimated future development costs generally will not reflect total finding and development costs related to reserves additions for that year. The three-year average is calculated based on the total capital and total reserves over the three-year time period.



COGP Finding, Development and Acquisition Costs(a)(b)
Including Future Development Costs

F&D Costs per boe
----------------------------------------------------------------------------
3-year
Total Proved Average(c) 2008 2007 2006
------------- ---------------------------------------------
Including revisions 32.53 49.36 20.39 25.06
Excluding revisions 30.44 35.70 25.55 24.76
Proved plus Probable
---------------------
Including revisions 29.97 36.25 24.42 23.99
Excluding revisions 23.39 28.75 20.23 16.80


FD&A Costs per boe
----------------------------------------------------------------------------
3-year
Total Proved Average(c) 2008 2007 2006
------------- ---------------------------------------------
Including revisions 36.54 48.36 39.76 30.11
Excluding revisions 35.96 36.45 41.48 30.07
Proved plus Probable
---------------------
Including revisions 24.34 35.28 23.31 23.04
Excluding revisions 23.25 28.93 22.85 22.12


Notes:
(a) F&D costs are based on Company share reserves.
(b) BOEs may be misleading, particularly if used in isolation. A BOE
conversion ratio of 6 Mcf: 1 bbl is based on an energy equivalency
conversion method primarily applicable at the burner tip and does not
represent a value equivalency at the wellhead.
(c) Three year average is the average of 2006, 2007 and 2008 calculated
based on the total capital and total reserves over the three-year time
period.


National Instrument 51-101

Estimation and reporting of oil and natural gas reserves in Canada were governed by National Policy 2B (NP 2B) from the late 1970's until 2003. Effective September 2003 the Canadian Securities Administrators implemented new standards that govern all aspects of reserves disclosure in the form of National Instrument 51-101 (NI 51-101). NI 51-101 requirements were updated effective December 28, 2007. NI 51-101 establishes prescribed disclosures regarding oil and natural gas information. NI 51-101 also enhanced corporate governance by mandating the involvement of independent reserves evaluators in the preparation of reserves data and assigning responsibility for the content of reserves data directly to management and the board of directors. Provident's reserves have been evaluated in accordance with the Canadian Oil and Gas Evaluation Handbook Volumes 1 and 2 ("COGEH") and comply with NI 51-101. Under NI 51-101, proved reserves are defined as having a high degree of certainty to be recoverable. Probable reserves are defined as those reserves that are less certain to be recovered than proved reserves. The targeted levels of certainty, in aggregate, are at least 90 percent probability that the quantities actually recovered will equal or exceed the estimated proved reserves and at least 50 percent probability that the quantities recovered will equal or exceed the sum of the estimated proved plus probable reserves. Under NI 51-101 standards proved plus probable are considered a "best estimate" of future recoverable reserves. The following outlines some of the key reserves definitions according to NI 51-101.

Reserve Definitions

Acquisitions and Dispositions: Positive or negative changes to the reserves as a result of purchasing or selling all or a portion of an interest in oil and gas properties.

Closing Balance: Reserves assigned at the end of the period.

Company Share: Includes working interest volumes before the deduction of royalties plus volumes equivalent to royalty interests received from others.

Drilling Extensions: Additions to reserves resulting from capital expenditures for step-out drilling in previously discovered reservoirs.

Economic Factors: Changes to reserves between the current and previous reporting periods resulting from different price forecasts, inflation rates, operating and capital cost escalation and regulatory changes.

Exploration Discoveries: Additions to reserves where no reserves were previously booked.

Improved Recovery: Additions to reserves resulting from capital expenditures associated with the installation of enhanced recovery schemes that were not previously included in the reserves category.

Infill Drilling: Additions to reserves resulting from capital expenditures for wells that were drilled in previously discovered reservoirs but were not drilled for enhanced recovery schemes. These additions were not previously included in the initial reserves assignment.

Net Reserves: Includes the company's share of gross reserves after the deduction of royalties plus volumes equivalent to royalty interests received from others and excludes volumes equivalent to royalties paid to others.

Opening Balance: Reserves assigned at the end of the last reporting period.

Production: Reductions in reserves due to production during the reporting period.

Technical Revisions: Positive or negative revisions to a reserves entity resulting from new technical data or revised interpretations on previously assigned reserves.

Working Interest: The Company's interest before royalties paid to or received from others.

Management's Discussion & Analysis

The following analysis provides a detailed explanation of Provident's operating results for the quarter and year ended December 31, 2008 compared to the quarter and year ended December 31, 2007 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, 2009.

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 ("COGP" or "Provident Upstream"), and Provident Midstream. Provident's Upstream business produces crude oil and natural gas from seven core areas in the western Canadian sedimentary basin. The Midstream business unit operates in Canada and the U.S.A. and extracts, processes, markets, transports and offers storage of natural gas liquids within the integrated facilities at Younger in British Columbia, Redwater and Empress in Alberta, Kerrobert in Saskatchewan, Sarnia in Ontario, Superior in Wisconsin and Lynchburg in Virginia. Effective in the first quarter of 2008, Provident's United States oil and natural gas production ("USOGP") business was accounted for as discontinued operations and comparative figures have been reclassified to conform with this presentation (see note 15 to the consolidated financial statements). The USOGP business was sold in two transactions, the first in June and the second in August, 2008.

The Trust has applied the proceeds, net of tax, on the sale of the USOGP business to reduce long-term debt, resulting in a ratio of net debt to total book value capitalization as at December 31, 2008 of 31 percent compared to 40 percent at December 31, 2007 (see "Liquidity and capital resources").

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

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

Fourth quarter highlights

The fourth quarter highlights section provides commentary on the fourth quarter of 2008 results compared to the fourth quarter of 2007. Definitions of terms used in this section, as appropriate, are defined in the year over year section of the Management's Discussion and Analysis following later in this press release.



Consolidated funds flow from operations and cash distributions


Consolidated Three months ended December 31,
----------------------------------------------------------------------------
($ 000s, except per unit data) 2008 2007 % Change
----------------------------------------------------------------------------
Funds Flow from Operations and Distributions
Funds flow from continuing operations $ 81,779 $ 135,776 (40)
Funds flow from discontinued operations(1) - 41,787 (100)
----------------------------------------------------------------------------
Total funds flow from operations $ 81,779 $ 177,563 (54)
Per weighted average unit - basic
and diluted(2) $ 0.32 $ 0.72 (56)
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Declared distributions $ 77,324 $ 89,063 (13)
Per Unit $ 0.30 $ 0.36 (17)
Percent of funds flow from operations
distributed(3) 95% 57% 67
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(1) Prior to the sale of USOGP, Provident owned approximately 22 per cent
of the MLP and 96 per cent of BreitBurn.
In accordance with generally accepted accounting principles (GAAP) in
Canada and the United States, these investments were consolidated into
Provident's results.
(2) Includes dilutive impact of unit options and convertible debentures.
(3) Calculated as declared distributions to unitholders divided by funds
flow from operations less distributions to non-controlling interests
of nil for the quarter (2007 - $22.1 million).


Fourth quarter 2008 funds flow from continuing operations was $81.8 million, 40 percent below the $135.8 million recorded in the fourth quarter of 2007. Provident Upstream's 2008 fourth quarter funds flow from operations was $47.2 million, a 20 percent decrease from the $58.7 million recorded in the comparable 2007 quarter. The drivers for the decrease were a nine percent decrease in commodity prices, a four percent decrease in production volumes and a 25 percent increase in production costs. Production volumes and costs were impacted by unscheduled turnarounds and additional maintenance related to cold weather. The reduction in funds flow was partially mitigated by the risk management program, which generated realized gains of $8.2 million in the fourth quarter of 2008, compared to $0.5 million in the comparable quarter of 2007.

The Provident Midstream business unit added $34.6 million to fourth quarter 2008 funds flow from operations, 55 percent below the $77.1 million recorded in the comparable 2007 quarter. This decrease reflects lower operating margins within the Midstream segment. A sharp drop in NGL sales prices driven by the decrease in crude oil price combined with higher value natural gas-based inventory had a negative impact on operating margins in the fourth quarter. This has been partially mitigated by the risk management program generating gains of $16.1 million in the fourth quarter of 2008 compared to a loss of $38.6 million in the comparable quarter in 2007.

Funds flow from operations in USOGP was nil compared to $41.8 million in the comparable 2007 quarter. The USOGP operations were sold prior to the fourth quarter of 2008.

Declared distributions in the fourth quarter of 2008 totaled $77.3 million, 95 percent of funds flow from operations. This compares to $89.1 million of declared distributions in fourth quarter of 2007, 57 percent of funds flow from operations, after distributions to non-controlling interests of $22.1 million.



Net (loss) income

Consolidated Three months ended December 31,
----------------------------------------------------------------------------
($ 000s, except per unit data) 2008 2007 % Change
----------------------------------------------------------------------------
Net (loss) income $ (43,248) $ 68,545 -
Per weighted average unit
- basic(1) and diluted(2) $ (0.17) $ 0.28 -
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(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 2008, Provident recorded a loss of $43.2 million compared to net income of $68.5 million in the comparable 2007 quarter. The fourth quarter of 2008 included a non-cash goodwill impairment charge of $416.9 million (see "Goodwill" in the annual section of this analysis) that was largely offset by $404.0 million of unrealized gains on financial derivative instruments. The fourth quarter of 2007 included a $179.1 million unrealized loss on financial derivative instruments and a $161.7 million dilution gain in discontinued operations related to Provident's change in ownership of the MLP. The preceding, combined with lower fourth quarter 2008 earnings before interest, taxes, depletion, depreciation, accretion and other non-cash items (EBITDA) from continuing operations accounts for the pre-tax swing in net (loss) income from the comparable quarter in 2007. Future income tax expense in the fourth quarter of 2008 was largely driven by the tax effect of the unrealized gain on financial derivative instruments. The goodwill impairment charge does not result in any corresponding future income tax recovery. Future income tax expense in the fourth quarter of 2008 was $52.4 million compared to a recovery of $71.8 million in the fourth quarter of 2007.

The Provident Upstream business segment had a net loss of $421.5 million, in the fourth quarter of 2008 compared to a 2007 fourth quarter net income of $16.9 million. The majority of the 2008 fourth quarter net loss was due to a non-cash goodwill impairment charge of $416.9 million. This, combined with a 21 percent decrease in EBITDA and a $44.4 million increase in future income taxes, partially offset by a $ 43.5 million increase in unrealized gains on financial derivative instruments accounts for the quarter over quarter change.

The Provident Midstream segment had net income of $359.2 million in the fourth quarter of 2008, compared to a net loss of $62.0 million in the fourth quarter of 2007. The increase was driven by a $377.7 million unrealized gain on financial derivative instruments in the fourth quarter of 2008 compared to a loss of $161.8 million in 2007. This increase to net income was partially offset by a $51.7 million decrease in Midstream EBITDA as well as a future income tax expense of $52.8 million in 2008 compared to a recovery in 2007 of $27.0 million.

Net income from discontinued operations (USOGP) was $19.1 million in the fourth quarter of 2008 with a comparative net income of $113.6 million for 2007. USOGP was sold in the second and third quarters of 2008. The fourth quarter 2008 results represent an adjustment to the provision for income taxes related to the sale. Net income from discontinued operations in the fourth quarter of 2007 was primarily driven by a $161.7 million dilution gain related to Provident's change in ownership of the MLP.

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 extends up to five 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 (EBITDA) within its segment disclosure. EBITDA is a non-GAAP measure. A reconciliation between EBITDA and loss from continuing operations before taxes follows:



Three months ended December 31,
----------------------------------------------------------------------------
($ 000s) 2008 2007 % Change
----------------------------------------------------------------------------
EBITDA $ 87,423 $ 152,432 (43)
Adjusted for:
Cash interest (9,998) (16,008) (38)
Unrealized gain (loss) on financial
derivative instruments 404,023 (179,061) -
Goodwill impairment (416,890) - -
Depletion, depreciation and accretion
and other non-cash expenses (78,438) (73,757) 6
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Loss from continuing operations
before taxes $ (13,880) $ (116,394) (88)
----------------------------------------------------------------------------
----------------------------------------------------------------------------


The following table reconciles funds flow from operations with cash provided
by operating activities and distributions to unitholders:

Reconciliation of funds flow
from operations to distributions Three months ended December 31,
----------------------------------------------------------------------------
($ 000s, except per unit data) 2008 2007 % Change
----------------------------------------------------------------------------
Cash provided by operating activities $ 150,032 $ 137,330 9
Change in non-cash operating
working capital (70,677) 38,511 -
Site restoration expenditures 2,424 1,722 41
----------------------------------------------------------------------------
Funds flow from operations 81,779 177,563 (54)
Distributions to non-controlling
interests - (22,124) (100)
Cash retained for financing and
investing activities (4,455) (66,376) (93)
----------------------------------------------------------------------------
Distributions to unitholders 77,324 89,063 (13)
Accumulated cash distributions,
beginning of period 1,535,144 1,171,114 31
----------------------------------------------------------------------------
Accumulated cash distributions,
end of period $1,612,468 $1,260,177 28
----------------------------------------------------------------------------
Cash distributions per unit $ 0.30 $ 0.36 (17)
----------------------------------------------------------------------------
----------------------------------------------------------------------------


Taxes

Three months ended December 31,
----------------------------------------------------------------------------
($ 000s) 2008 2007 % Change
----------------------------------------------------------------------------
Capital tax expense $ 485 $ 510 (5)
Current and withholding tax recovery (4,453) (5) 88,960
Future income tax expense (recovery) 52,379 (71,815) -
----------------------------------------------------------------------------
----------------------------------------------------------------------------
$ 48,411 $ (71,310) -
----------------------------------------------------------------------------
----------------------------------------------------------------------------


Fourth quarter Saskatchewan capital taxes totaled $0.5 million, consistent with the $0.5 million recorded in the fourth quarter of 2007.

The current and withholding tax recovery was $4.5 million in the fourth quarter of 2008. These recoveries arise from Provident's Midstream operations and are the result of lower fourth quarter income subject to tax.

The 2008 fourth quarter future tax expense of $52.4 million compares to a recovery of $71.8 million in the fourth quarter of 2007. The future 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 is not tax effected. The future income tax recovery in the quarter of 2007 was largely related to the unrealized loss on financial derivative instruments.



Interest expense

Continuing operations Three months ended December 31,
----------------------------------------------------------------------------
($ 000s, except as noted) 2008 2007 % Change
----------------------------------------------------------------------------

Interest on bank debt $ 5,015 $ 13,121 (62)
Interest on convertible debentures 4,983 4,986 -
Discontinued operations portion - (2,099) (100)
----------------------------------------------------------------------------
Total cash interest $ 9,998 $ 16,008 (38)
----------------------------------------------------------------------------
----------------------------------------------------------------------------

Weighted average interest rate on
all long-term debt 5.1% 5.9% (14)

Debenture accretion and other
non-cash interest expense 1,465 1,173 25
----------------------------------------------------------------------------
Total interest expense $ 11,463 $ 17,181 (33)
----------------------------------------------------------------------------
----------------------------------------------------------------------------


Interest expense decreased for the quarter as compared to the same quarter in 2007 due to significantly lower debt levels and lower market interest rates. Cash proceeds on the sale of USOGP in June and August of 2008, amounting to $457.9 million, net of tax, were used to pay down debt.

Commodity price risk management program

In the fourth quarter of 2008, when commodity prices dropped dramatically, the Program assisted with stabilizing cash flow by contributing $24.3 million, or 30 percent of fourth quarter funds flow from operations.

A summary of Provident's risk management contracts executed during the fourth quarter of 2008 is contained in the following tables.



Activity in the Fourth Quarter:

Provident Midstream

Volume
Year Product (Buy)/Sell Terms Effective Period
----------------------------------------------------------------------------
2009 Crude Oil (140) Bpd US $65.04 per bbl(8) January 1 - March 31
(1,052) Bpd Cdn $70.21 per bbl(11) January 1 - November 30
323 Bpd US $57.78 per bbl(9) May 1 - May 31
2,000 Bpd US $69.73 per bbl(10) January 1 - December 31
Natural Gas 2,500 Gjpd Cdn $6.56 per gj(9) January 1 - January 31
US $0.94 per gallon
Propane 200 Bpd (4)(8) January 1 - March 31
333 Bpd US $0.99 per gallon
(5)(9) January 1 - March 31
333 Bpd US $0.95 per gallon
(4)(9) January 1 - March 31
Natural (2,000) Bpd US $1.36 per gallon
Gasoline (10) January 1 - December 31
Normal (1,473) Bpd US $0.76 per gallon
Butane (10) April 1 - December 31

2010 Normal
Butane (1,500) Bpd US $0.76 per gallon
(10) January 1 - March 31
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(1) The above table represents a number of transactions entered into over
the fourth quarter 2008.
(2) Natural gas contracts are settled against AECO monthly index.
(3) Crude Oil contracts are settled against NYMEX WTI calendar average.
(4) Propane contracts are settled against Belvieu C3 TET.
(5) Propane contracts are settled against Conway In-Well C3.
(6) Normal Butane contracts are settled against Belvieu NC4 TET.
(7) Natural Gasoline contracts are settled against Belevieu NON-TET
Natural Gasoline.
(8) Conversion of Crude Oil BTU contracts to liquids.
(9) Midstream inventory price stabilization contracts.
(10) Midstream margin contracts.
(11) BTU re-balancing of Crude Oil contracts.


Settlement of commodity contracts

The following is a summary of the net cash flow to settle commodity contracts during the fourth quarter of 2008. For comparative purposes, the 2007 amounts are also summarized.

i) Provident Upstream

a) Crude Oil

For the quarter ending December 31, 2008, Provident received $6.1 million (2007 - paid $4.6 million) to settle various oil market based contracts on an aggregate volume of 0.4 million barrels (2007 - 0.6 million barrels).

b) Natural Gas

For the quarter ending December 31, 2008, Provident received $2.1 million (2007 - $5.1 million) to settle various natural gas market based contracts on an aggregate volume of 1.9 million gj's (2007 - 4.5 million gj's).

ii) Provident Midstream

For the quarter ending December 31, 2008 Provident paid $4.0 million (2007 - received $0.2 million) to settle midstream oil market based contracts on an aggregate volume of 1.3 million barrels (2007 - 0.4 million barrels) and paid $13.1 million (2007 - $16.8 million) to settle midstream natural gas market based contracts on an aggregate volume of 6.7 million gj's (2007 - 6.6 million gj's). In addition, Provident received $34.2 million (2007 - paid $26.6 million) to settle midstream NGL market based contracts on an aggregate volume of 0.2 million barrels (2007 - 2.4 million barrels).

Provident also paid $1.8 million (2007 - received $4.6 million) to settle midstream-related foreign exchange contracts, and received $0.8 million (2007 - nil) to settle various electricity-based contracts.

iii) Corporate

a) Foreign exchange contracts

For the quarter ending December 31, 2008 Provident received $21.6 million (2007 - nil) to settle various corporate-related foreign exchange based contracts. Realized gains and losses on corporate-related foreign exchange contracts are included in foreign exchange (gain) loss and other on the consolidated statement of operations and are allocated to the reporting segments for segmented reporting purposes. The gain in 2008 relates primarily to contracts put in place to mitigate the foreign exchange risk associated with U.S.-denominated taxes payable in connection with the sale of discontinued operations (USOGP).

Provident's Commodity Price Risk Management activities are also discussed in the year over year section of Management's Discussion and Analysis and in note 13 to the consolidated financial statements.



Provident Upstream segment review

Crude oil and natural gas liquids prices

Provident Upstream Three months ended December 31,
----------------------------------------------------------------------------
($ per bbl) 2008 2007 % Change
----------------------------------------------------------------------------

Oil per barrel
WTI (US$) $ 58.73 $ 90.68 (35)
Exchange rate (from US$ to Cdn$) $ 1.21 $ 0.98 23
WTI expressed in Cdn$ $ 71.21 $ 89.03 (20)
----------------------------------------------------------------------------
----------------------------------------------------------------------------

Realized pricing before financial
derivative instruments
Crude oil $ 47.33 $ 61.75 (23)
Natural gas liquids $ 47.64 $ 63.63 (25)
----------------------------------------------------------------------------
Crude oil and natural gas liquids $ 47.36 $ 61.94 (24)
----------------------------------------------------------------------------
----------------------------------------------------------------------------


The above prices are net of transportation expense.

In the fourth quarter of 2008 Provident's realized oil and natural gas liquids price, prior to the impact of financial derivative instruments, decreased by 24 percent to $47.36 per barrel compared to $61.94 per barrel in the fourth quarter of 2007. The decrease was related to a 35 percent lower US$ WTI crude oil price partially offset by a weaker Canadian dollar.



Natural gas price

Provident Upstream Three months ended December 31,
----------------------------------------------------------------------------
($ per mcf) 2008 2007 % Change
----------------------------------------------------------------------------

AECO monthly index (Cdn$ per mcf) $ 6.78 $ 6.00 13
Corporate natural gas price per
mcf before financial
derivative instruments (Cdn$) $ 6.63 $ 6.08 9
----------------------------------------------------------------------------
----------------------------------------------------------------------------


The above prices are net of transportation expense.

Provident's fourth quarter 2008 realized natural gas price, prior to the impact of financial derivative instruments, increased nine percent as compared to the fourth quarter of 2007, lower than the increase in the benchmark AECO index price of 13 percent. Provident's gas portfolio includes aggregator contracts sold on a term basis that can differ from the benchmark price and sells to the spot market on monthly or daily indices and receives prices which take into account heat content.



Production

Provident Upstream Three months ended December 31,
----------------------------------------------------------------------------
2008 2007 % Change
----------------------------------------------------------------------------
Daily production
Crude oil (bpd) 12,307 11,252 9
Natural gas liquids (bpd) 1,134 1,277 (11)
Natural gas (mcfd) 80,450 92,584 (13)
----------------------------------------------------------------------------
Oil equivalent (boed)(1) 26,849 27,960 (4)
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(1) Provident reports equivalent production converting natural gas to oil
on a 6:1 basis.


Production decreased four percent to 26,849 boed during the fourth quarter of 2008 as compared to 27,960 boed in 2007. The decrease was primarily a result of natural production declines, an eight-day third-party gas pipeline outage in Northwest Alberta impacting approximately 24 mmcfed natural gas and associated oil production. As well, cold weather downtime had an impact on production primarily in the Dixonville and Lloydminster areas. The decrease was partially offset by increased oil production from the Triwest Energy Inc. ("Triwest") acquisition on December 3, 2007, as well as an active drilling and optimization program. The Triwest acquisition is included in the Southeast Saskatchewan core area.

Production for the fourth quarter of 2008 was weighted 50 percent natural gas, and 50 percent crude oil and natural gas liquids. This compared to fourth quarter 2007 production weighted 55 percent natural gas and 45 percent crude oil and natural gas liquids.



Provident Upstream's production summarized by core areas is as follows:

Three months ended December 31,
----------------------------------------------------------------------------
Provident Upstream 2008 2007 % Change
----------------------------------------------------------------------------
Daily Production - by area (boed)(1)
West Central Alberta 6,005 6,775 (11)
Southern Alberta 4,990 5,493 (9)
Northwest Alberta 4,283 4,714 (9)
Dixonville 3,750 4,090 (8)
Southeast Saskatchewan 2,866 2,144 34
Southwest Saskatchewan 1,208 1,527 (21)
Lloydminster 3,747 3,217 16
----------------------------------------------------------------------------
26,849 27,960 (4)
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(1) Provident reports equivalent production converting natural gas to oil
on a 6:1 basis.


Revenue and royalties


Provident Upstream Three months ended December 31,
----------------------------------------------------------------------------
($ 000s except per boe and mcf data) 2008 2007 % Change
----------------------------------------------------------------------------
----------------------------------------------------------------------------

Oil
Revenue $ 53,592 $ 63,920 (16)
Realized gain (loss) on financial
derivative instruments 6,089 (4,675) -
Royalties (9,159) (12,491) (27)
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Net revenue $ 50,522 $ 46,754 8
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Net revenue (per barrel) $ 44.62 $ 45.17 (1)
Royalties as a percentage of revenue 17.1% 19.5%

Natural gas
Revenue $ 49,088 $ 51,766 (5)
Realized gain on financial derivative
instruments 2,130 5,174 (59)
Royalties (7,643) (9,437) (19)
----------------------------------------------------------------------------
Net revenue $ 43,575 $ 47,503 (8)
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Net revenue (per mcf) $ 5.89 $ 5.58 6
Royalties as a percentage of revenue 15.6% 18.2%

Natural gas liquids
Revenue $ 4,970 $ 7,477 (34)
Royalties (1,299) (1,882) (31)
----------------------------------------------------------------------------
Net revenue $ 3,671 $ 5,595 (34)
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Net revenue (per barrel) $ 35.19 $ 47.62 (26)
Royalties as a percentage of revenue 26.1% 25.2%

Total
Revenue $ 107,650 $ 123,163 (13)
Realized gain on financial derivative
instruments 8,219 499 1,547
Royalties (18,101) (23,810) (24)
----------------------------------------------------------------------------
Net revenue $ 97,768 $ 99,852 (2)
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Net revenue (per boe) $ 39.58 $ 38.81 2
Royalties as a percentage of revenue 16.8% 19.3%
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Note: the above revenue, net revenue and net revenue per boe figures are
presented net of transportation expenses.


In the fourth quarter of 2008, Provident Upstream production revenue was $107.7 million, a decrease of 13 percent from $123.2 million in 2007. The decrease in revenue is a result of a four percent decrease in production and a 24 percent decrease in crude oil and natural gas liquids prices, partially offset by a nine percent increase in Provident's realized natural gas price. Total royalties, which are price sensitive and affected by production levels, as a percentage of revenue decreased reflecting the lower crude oil prices, lower gas production, and capital expenditures on natural gas facilities. The preceding factors, as well as the $7.7 million increase in realized gains on financial derivative instruments account for net revenue of $97.8 million in the fourth quarter of 2008, two percent below the $99.9 million recorded in the fourth quarter of 2007. Net revenue per boe in the fourth quarter of 2008 was $39.58 per boe, an increase of two percent from $38.81 per boe in the fourth quarter of 2007.



Production expenses


Provident Upstream Three months ended December 31,
----------------------------------------------------------------------------
($ 000s, except per boe data) 2008 2007 % Change
----------------------------------------------------------------------------
Production expenses $ 37,159 $ 29,644 25
Production expenses (per boe) $ 15.04 $ 11.52 31
----------------------------------------------------------------------------
----------------------------------------------------------------------------


Fourth quarter 2008 production expenses increased 25 percent to $37.2 million from $29.6 million in the comparable 2007 quarter. On a boe basis, quarter over quarter production expenses increased by 31 percent to $15.04 per boe from $11.52 per boe in the comparable 2007 quarter. In general, industry operating costs in the fourth quarter of 2008 trended above costs in the comparable 2007 quarter. Specific to Provident, operating costs for crude oil production are higher on a per boe basis than natural gas production and, in the fourth quarter of 2008, crude oil and natural gas liquids contributed 50 percent of the production mix, up from 45 percent in the comparable quarter. As well, the increase reflects unscheduled turnarounds in Northwest Alberta performed to take advantage of circumstances resulting from the third-party pipeline outage. This has a dual impact on the boe metric as it couples increased costs with reduced production, however it avoids offline production in future periods. In addition, unscheduled turnarounds in Southeast and Southwest Saskatchewan and additional downhole costs associated with well servicing during the cold weather in December had an unfavorable impact on operating costs across all of the core areas.



Operating netback


Provident Upstream Three months ended December 31,
----------------------------------------------------------------------------
($ per boe) 2008 2007 % Change
----------------------------------------------------------------------------
Netback per boe
Gross production revenue $ 43.58 $ 47.88 (9)
Royalties (7.33) (9.26) (21)
Operating costs (15.04) (11.52) 31
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Field operating netback 21.21 27.10 (22)
Realized gain on financial derivative
instruments 3.33 0.19 1,653
----------------------------------------------------------------------------
Operating netback after realized
financial derivative instruments $ 24.54 $ 27.29 (10)
----------------------------------------------------------------------------
----------------------------------------------------------------------------


Provident Upstream operating netbacks have transportation expense netted against gross production revenue.

The fourth quarter 2008 field operating netback decreased 22 percent to $21.21 per boe from $27.10 per boe in the comparable quarter in 2007. The nine percent drop in gross production revenue per boe reflects the 24 percent decrease in crude oil and natural gas liquids prices combined with an increased weighting of crude oil and natural gas liquids production to 50 percent from 45 percent in the comparable quarter in 2007. This was partially offset by the nine percent higher realized price for natural gas. The 31 percent higher per boe production expenses is explained above. Royalties, which are price sensitive, decreased by 21 percent on a boe basis reflecting the lower total liquids mix prices, prior to the impact of financial derivative instruments. The fourth quarter 2008 operating netback after financial derivative instruments decreased by 10 percent to $24.54 from $27.29 reflecting the preceding factors as well as the 2008 fourth quarter gain on financial derivative instruments of $3.33 per boe compared to $0.19 per boe in the comparable quarter in 2007.



General and administrative


Provident Upstream Three months ended December 31,
----------------------------------------------------------------------------
($ 000s, except per boe data) 2008 2007 % Change
----------------------------------------------------------------------------

Cash general and administrative $ 8,776 $ 5,583 57
Non-cash unit based compensation (3,040) (3,014) 1
----------------------------------------------------------------------------
$ 5,736 $ 2,569 123

Cash general and administrative (per boe) $ 3.55 $ 2.17 64
----------------------------------------------------------------------------
----------------------------------------------------------------------------


Cash general and administrative expenses for Provident Upstream in the fourth quarter increased 57 percent to $8.8 million from $5.6 million recorded in the 2007 comparable quarter. On a boe basis the cash general and administrative expenses recorded in fourth quarter 2008 increased 64 percent to $3.55 from $2.17 in the fourth quarter of 2007. The increase in cash general and administrative expenses is due to higher office-related expenses, particularly rent, and costs associated with the previously announced strategic evaluation of Provident's business units, including an internal structural reorganization completed in the fourth quarter of 2008.

Non-cash unit based compensation was a recovery of $3.0 million in the fourth quarter of 2008 and 2007. The recovery reflects a reduction to employee incentive costs due to lower unit prices and total return performance of the Trust as measured against an industry peer group.



Capital expenditures

Provident Upstream Three months ended December 31,
----------------------------------------------------------------------------
($ 000s) 2008 2007
----------------------------------------------------------------------------

Capital expenditures - by category
Geological, geophysical and land $ 7,055 $ 619
Drilling and recompletions 28,763 37,485
Facilities and equipment 10,682 5,827
Office and other (4,067) 8,614
----------------------------------------------------------------------------
Total additions $ 42,433 $ 52,545
----------------------------------------------------------------------------
----------------------------------------------------------------------------

Capital expenditures - by area
West central Alberta $ 3,383 $ 2,159
Southern Alberta 6,113 1,878
Northwest Alberta 22,561 5,892
Dixonville 7,291 26,130
Southeast Saskatchewan 4,166 1,845
Southwest Saskatchewan 1,110 2,913
Lloydminster 1,592 3,383
Other (3,783) 8,345
----------------------------------------------------------------------------
Total additions $ 42,433 $ 52,545
----------------------------------------------------------------------------
----------------------------------------------------------------------------

Property acquisitions, net $ 4,594 $ 1,481
----------------------------------------------------------------------------
----------------------------------------------------------------------------


In the fourth quarter of 2008, Provident's Upstream business unit spent $46.5 million on capital expenditures before office and other capital costs. Internal development activities included 6.5 net wells drilled during the quarter with a 100 percent success rate. Provident was most active in Northwest Alberta in the fourth quarter of 2008, spending $22.6 million on drilling and completion activities and facility work associated with the start up of the 2008/2009 winter drilling program, directed towards the emerging Pekisko opportunity. In addition, 18.8 net sections (approximately 12,000 acres) of undeveloped land was purchased to pursue the Pekisko play.

Expenditures in the Dixonville area were $7.3 million including 2.0 net horizontal wells drilled. Dixonville spending was lower as the primary drilling of the pool was completed last year and expenditures have been directed towards the full field waterflood program that is awaiting regulatory approval to advance the project beyond the pilot stage. In Southeast Saskatchewan, $4.2 million was spent primarily on its drilling and completion program which targeted light oil drilling on the Triwest assets resulting in 1.8 net wells drilled. The $12.4 million of capital spent in the remaining areas included drilling, completion, tie-ins, recompletions, facility upgrades and production optimization activities.

In the fourth quarter of 2008, Provident also spent $4.6 million on property acquisitions relating to additional working interests in Northwest Alberta.

In addition, $4.1 million was received in the fourth quarter of 2008 related to a recovery of leasehold improvement costs to occupy the new head office space.



Depletion, depreciation and accretion (DD&A)

Provident Upstream Three months ended December 31,
----------------------------------------------------------------------------
($ 000s, except per boe data) 2008 2007 % Change
----------------------------------------------------------------------------

DD&A $ 76,527 $ 70,865 8
DD&A (per boe) $ 30.98 $ 27.55 12
----------------------------------------------------------------------------
----------------------------------------------------------------------------


The Provident Upstream DD&A rate of $30.98 per boe for the fourth quarter of 2008 increased by 12 percent compared to $27.55 per boe for the fourth quarter of 2007. The increase was primarily due to 2008 expenditures on geological, geophysical, land and facilities, which added to costs to be depleted without directly adding proved reserves, and as a result of the acquisition of Triwest in December 2007.

Accretion expense associated with asset retirement obligations was $0.9 million in the fourth quarter of 2008 compared to $0.7 million in the fourth quarter of 2007.

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

Provident Commercial Services.



Provident Midstream business unit results can be summarized as follows:

Three months ended December 31,
----------------------------------------------------------------------------
($ 000s) 2008 2007 % Change
----------------------------------------------------------------------------

Empress East Margin $ 900 $ 77,110 (99)
Redwater West Margin 4,142 41,709 (90)
Commercial Services Margin 12,095 19,587 (38)
----------------------------------------------------------------------------
Gross operating margin 17,137 138,406 (88)
Realized gain (loss) on financial
derivative instruments 16,098 (38,631) -
Cash general and administrative expenses (8,418) (6,355) 32
Foreign exchange gain (loss) and other 12,849 (3,997) -
----------------------------------------------------------------------------
Provident Midstream EBITDA $ 37,666 $ 89,423 (58)
----------------------------------------------------------------------------
----------------------------------------------------------------------------


Gross operating margin

The Empress East business line extracts NGLs from natural gas at the Empress straddle plants and sells finished products into markets in Central Canada and the Eastern United States. The margin in this business is determined primarily by the "frac spread ratio", which is the ratio between crude oil prices and natural gas prices. Traditionally the higher the ratio, the better this business line will perform. 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 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 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.

In the fourth quarter of 2008, the gross operating margin for Empress East was $0.9 million (2007 - $77.1 million). This decrease reflects the operating margin squeeze that resulted from both a dramatic drop in prices received for product sales compounded by a high per unit cost of inventory entering the fourth quarter of 2008. Prices received in the fourth quarter of 2008 for propane-plus products were 42 percent lower than the fourth quarter of 2007 and tracked the significant decrease in crude oil prices. The average frac spread ratio in the fourth quarter of 2008 was 11.2, 29 percent below the average of 15.7 in the fourth quarter of 2007. A further driver for the drop in 2008 fourth quarter gross operating margin was that, as winter sales demand for propane increased late in the quarter, the frac spread ratio had deteriorated significantly, from 15.4 in October to 7.6 in December. In addition to lower frac spread ratios, the fourth quarter experienced a significant decline in the sales price of propane relative to the price of crude oil. Posted prices at Mont Belvieu for propane in the fourth quarter of 2008 averaged 57 percent of WTI (U.S. $58.73), compared to 70 percent of WTI (U.S. $90.68) in the comparable quarter of 2007. A final factor on the sales side, sales volumes in the fourth quarter of 2008 for propane-plus products was nine percent lower than the fourth quarter of 2007.

Further contributing to the reduced operating margins for Empress East in the quarter was the cost of product available for sale. The costs in the fourth quarter of 2008 reflected opening inventory balances that built up in the second and third quarter of 2008, when natural gas prices at AECO averaged $9.30 per mcf, 43 percent above the $6.49 per mcf average natural gas price for the comparable 2007 quarters. This, combined with continuing to build inventory in a falling market in the fourth quarter of 2008, drove an eight percent increase in cost of goods sold, on a per unit basis, over the comparative quarter of 2007.

Subsequent to year end, conditions have shown some improvement. The frac spread ratio in January 2009 has recovered to 8.3, and the price of propane as a percentage of WTI increased to 72 percent. As well, the weighted average cost of inventory at December 31, 2008 on a per unit basis was 13 percent below the per unit cost of inventory at September 30, 2008.

The Redwater West business line purchases an NGL mix from various producers and fractionates it into finished products at the Redwater fractionation facility near Edmonton, Alberta. Because the feedstock for this business line is primarily NGL mix rather than natural gas, the frac spread ratio has a smaller impact on margin than in the Empress East business line. 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 participation in the condensate market over the past year, reflecting the increased diluent demand for heavy oil production.

In the fourth quarter of 2008, the operating margin for Redwater West was $4.1 million (2007 - $41.7 million). The decrease in margin is primarily due to 40 percent lower selling prices tracking the significant drop in crude oil prices, as well as the deterioration in the price of NGL products as a percentage of WTI. Cost of goods sold also declined reflecting the market based pricing for the majority of this product. The decrease in cost of goods sold, on a per unit basis, for Redwater West was 31 percent, when compared to the fourth quarter of 2007, which is less than the decline in related selling prices. In periods of falling market prices, cost of goods sold in Redwater West generally does not decline as fast as revenue. This is due to the fact that inventory, which was built up in prior periods when prices were higher, is being sold in a declining price environment. A volume increase of nine percent was primarily related to condensate.

The Commercial Services business line generates income from stable fee-for-service contracts to provide fractionation, storage, loading, and marketing services to upstream producers. Income from pipeline tariffs from Provident's ownership in NGL pipelines is also included in this business line. In the fourth quarter of 2008, the margin for this business line was $12.1 million (2007 - $19.6 million). The 2008 fourth quarter operating margin, while 38 percent lower for this business line than the 2007 comparable quarter, does incorporate a 53 percent increase in the fees associated with the offloading facility, due to increased condensate business. The fourth quarter of 2007 included an anomaly whereby Commercial Services benefited from payments for product quality adjustments related to our condensate offloading facility that covered prior quarters. These payments increased the fourth quarter operating margin in 2007, are generally non-recurring and account for the quarter over quarter decrease in operating margin.

Operations - Provident Midstream NGL sales volumes

Provident Midstream sold 120,222 bpd in the fourth quarter of 2008, down 12 percent when compared with the fourth quarter of 2007. Decreased propane-plus volumes in Empress East were largely offset by increased propane-plus volumes in Redwater West. Lower overall sales volume reflects lower sales of ethane due to reduced demand in the quarter.

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

Fourth quarter 2008 EBITDA of $37.7 million decreased $51.7 million or 58 percent from $89.4 million in the fourth quarter of 2007. A $121.3 million decrease in gross operating margin as described above was partially offset by a $54.7 million increase in realized gains on financial derivative instruments, when compared with the fourth quarter of 2007 as well as foreign exchange gains on U.S. dollar-based transactions. Funds flow from operations for the fourth quarter of 2008 was $34.6 million, a decrease of $42.5 million or 55 percent compared to the $77.1 million for the fourth quarter 2007. The decrease in funds flow from operations reflects lower EBITDA partially offset by lower interest charges and higher income tax recoveries.

Cash general and administrative expenses and other were $8.4 million in the fourth quarter of 2008, an increase of $2.1 million compared with $6.3 million in the fourth quarter of 2007. The increase is due to higher office-related expenses, particularly rent, and costs associated with the previously announced strategic evaluation of Provident's business units, including an internal structural reorganization completed in the fourth quarter of 2008.

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

Capital expenditures

Provident Midstream capital expenditures for the fourth quarter of 2008 totaled $12.5 million. In the quarter, $12.8 million was spent on the condensate offloading and terminalling facility, expansion to the recently completed truck loading facilities, and continued development of cavern storage. In addition, $1.9 million was spent on sustaining capital requirements and a $2.2 million recovery was received on office furniture and equipment.



2008 Year end results

Consolidated funds flow from operations and cash distributions

Consolidated Year ended December 31,
----------------------------------------------------------------------------
($ 000s, except per unit data) 2008 2007 % Change
----------------------------------------------------------------------------

Funds Flow from Operations and Distributions
Funds flow from continuing operations $ 517,622 $ 382,684 35
Funds flow from discontinued operations
(USOGP) (1) 137,535 85,571 61
----------------------------------------------------------------------------
Total funds flow from operations $ 655,157 $ 468,255 40
Per weighted average unit - basic and
diluted (2) $ 2.57 $ 2.04 26
----------------------------------------------------------------------------
Declared distributions $ 352,291 $ 333,352 6
Per Unit $ 1.38 $ 1.44 (4)
Percent of funds flow from operations
distributed (3) 58% 77% (25)
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(1) Prior to the sale of USOGP, Provident owned approximately 22 per cent of
the BreitBurn Energy Partners, L.P. (MLP) and 96 per cent of BreitBurn
Energy Company L.P. In accordance with generally accepted accounting
principles (GAAP) in Canada and the United States, these investments
were consolidated into Provident's results. On a proportionate basis,
Provident's share of funds flow from operations related to discontinued
operations (USOGP) for the year ended December 31, 2008 was $57.9
million.
(2) Includes dilutive impact of unit options and convertible debentures.
(3) Calculated as declared distributions to unitholders divided by funds
flow from operations less distributions to non-controlling interests of
$51.4 million (2007 - $35.8 million).


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

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

For the year ended December 31, 2008, funds flow from operations increased $186.9 million or 40 percent to $655.2 million from $468.3 million for 2007. On a per unit basis, funds flow from operations increased 26 percent in 2008 to $2.57 per unit from $2.04 per unit in 2007. Provident Upstream generated $338.7 million, Provident Midstream $179.0 million and discontinued operations (USOGP) contributed $137.5 million of funds flow from operations during 2008. During 2007, Provident Upstream generated funds flow from operations of $204.3 million, Provident Midstream $178.4 million, and discontinued operations (USOGP) $85.6 million.

Canadian oil and gas operations contributed funds flow from operations of $338.7 million in 2008, an increase of $134.4 million or 66 percent when compared with $204.3 million from 2007. This increase was the result of higher realized crude oil, natural gas liquids and natural gas prices in the first nine months of 2008, combined with an increase in production.

The Midstream business unit added $179.0 million to 2008 funds flow from operations, compared with $178.4 million recorded in the year ended December 31, 2007. Midstream funds flow from operations reflects a decrease in EBITDA of $12.9 million or six percent, offset by reduced cash interest charges due to lower debt levels and a reduction in current taxes compared to 2007.

For the year ended December 31, 2008, funds flow from discontinued operations (USOGP) was $137.5 million, compared to the $85.6 million in 2007. The increase is primarily driven by increased production due to oil and gas property acquisitions by the MLP in 2007, combined with higher commodity prices. Prior to the sale of USOGP, Provident owned approximately 22 percent of the MLP and 96 percent of BreitBurn. In accordance with generally accepted accounting principles (GAAP) in Canada and the United States, these investments were consolidated into Provident's results. On a proportionate basis, Provident's share of funds flow from operations relating to discontinued operations (USOGP) for the year ended December 31, 2008 was $57.9 million. Management uses proportionate information to analyze operating performance. The proportionate information as presented here does not have any standardized meaning prescribed by Canadian GAAP and therefore may not be comparable with the calculation of similar measures for other entities. This proportionate information is not intended to be viewed as an alternative to the corresponding measures of financial performance calculated in accordance with Canadian GAAP.

Declared distributions in 2008 totaled $352.3 million, 58 percent of funds flow from operations, after distributions to non-controlling interests of $51.4 million. This compares to $333.4 million of declared distributions in 2007, 77 percent of funds flow from operations, after distributions to non-controlling interests of $35.8 million. In previous years, Provident has paid out between 67 percent and 102 percent of its annual funds flow from operations as distributions to unitholders. On a segmented basis, the Midstream business, due to its low sustaining capital requirements, effectively contributed 95 percent of its funds flow from operations for distribution in the year ended December 31, 2008. The remaining distributions were effectively contributed by the oil and natural gas production businesses (Provident Upstream and USOGP) representing 43 percent of their combined funds flow from operations in 2008.

Outlook

Continued price weakness and volatility in commodity markets is having a negative impact on the energy industry on a global scale. This market turmoil has resulted in reduced capital investment, activity levels and ongoing uncertainty in debt and equity markets in the first quarter of 2009. In the current environment, energy firms such as Provident will be challenged to generate cash flow comparable to levels achieved in recent years. Provident actively monitors commodity prices and market conditions on an ongoing basis and will continue to balance reinvestment of cash flow among capital expenditures, distributions and long term debt.

Provident Upstream has a 2009 capital budget of $88 million and plans to drill a total of 23.8 net wells. Approximately $36 million is being directed towards development of the Pekisko medium oil play in Northwest Alberta. Three new Pekisko wells have been drilled and surface facilities are now being installed that will enable year round production from four of the five Pekisko wells beginning in the second quarter of 2009. Approximately $19 million is allocated to the implementation of the first phase of the waterflood project in Dixonville. The remaining $33 million is budgeted for development initiatives in other areas. 2009 production is expected to average between 23,500 and 25,000 barrels of oil equivalent per day (boed). Subject to pricing assumptions, royalty rates are expected to fall this year to approximately 17 percent including the impact of the new Alberta royalty framework. Operating costs are expected to remain relatively stable in the first half of 2009, but should begin to moderate in the latter half of the year as labour, service and material costs deflate as development activity slows.

Provident Midstream has a 2009 capital budget of approximately $27 million. This budget will be used, in part, to complete two 500,000 barrel condensate caverns which will enter service at the Redwater facility in the summer of 2009. Work also continues on a third cavern of equal size that is expected to be complete in 2011. Upon completion of these caverns, Provident will own 6.6 million barrels of underground product storage at Redwater. A portion of the 2009 capital budget will be directed towards certain facility optimization and debottlenecking initiatives while approximately $6 million will be used for normal course facility maintenance. Provident is also allocating a portion of its 2009 capital budget towards the initial phases of a project to construct a depropanizer facility located in Michigan. The Michigan depropanizer is one of several options under consideration to mitigate the financial impact of the potential 6,000 barrels per day curtailment of NGL fractionation capacity at Sarnia which would take effect April 1, 2009, contingent on ongoing contractual negotiations with the facility owner.

NGL margins have strengthened in the first quarter of 2009 compared to the fourth quarter of 2008. This improvement is the result of substantially higher sale prices for propane and butane due to strong winter demand coupled with a lower cost of sales as the majority of the high cost inventory accumulated during 2008 has been depleted.



Distributions

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

Distribution Amount
Record Date Payment Date (Cdn$) (US$)(1)
----------------------------------------------------------------------------
2008
January 24, 2008 February 15, 2008 $ 0.12 0.12
February 25, 2008 March 14, 2008 0.12 0.12
March 24, 2008 April 15, 2008 0.12 0.12
April 22, 2008 May 15, 2008 0.12 0.12
May 23, 2008 June 13, 2008 0.12 0.12
June 20, 2008 July 15, 2008 0.12 0.12
July 22, 2008 August 15, 2008 0.12 0.12
August 22, 2008 September 15, 2008 0.12 0.11
September 22, 2008 October 15, 2008 0.12 0.10
October 22, 2008 November 14, 2008 0.12 0.10
November 25, 2008 December 15, 2008 0.09 0.07
December 22, 2008 January 15, 2009 0.09 0.07
----------------------------------------------------------------------------
2008 Cash Distributions paid as declared $ 1.38 1.29
----------------------------------------------------------------------------
----------------------------------------------------------------------------
2007 Cash Distributions paid as declared 1.44 1.35
2006 Cash Distributions paid as declared 1.44 1.26
2005 Cash Distributions paid as declared 1.44 1.20
2004 Cash Distributions paid as declared 1.44 1.10
2003 Cash Distributions paid as declared 2.06 1.47
2002 Cash Distributions paid as declared 2.03 1.29
2001 Cash Distributions paid as declared
- March 2001 - December 2001 2.54 1.64
----------------------------------------------------------------------------
Inception to December 31, 2008 - Distributions paid as
declared $ 13.77 10.60
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(1) Exchange rate based on the Bank of Canada noon rate on the payment date.


For Canadian tax purposes, 2008 distributions were determined to be 100 percent taxable with no tax deferred return of capital in the hands of Canadian unitholders. The 2007 comparables were 94.8 percent taxable and 5.2 percent tax deferred return of capital. Distributions received by U.S. resident unitholders in 2008 were considered to be 100 percent qualified dividend with no tax deferred return of capital. The 2007 comparables were considered to be 97.6 percent qualified dividend and 2.4 percent 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 income

Consolidated Year ended December 31,
----------------------------------------------------------------------------
($ 000s, except per unit data) 2008 2007 % Change
----------------------------------------------------------------------------

Net income $ 157,392 $ 30,434 417
Per weighted average unit
- basic (1) and diluted (2) $ 0.62 $ 0.13 377
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(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.


Consolidated Year ended December 31,
----------------------------------------------------------------------------
($ 000s) 2008 2007 % Change
----------------------------------------------------------------------------
Provident Upstream net (loss) income $ (306,050) $ 45,065 -
Provident Midstream net income (loss) 317,418 (161,020) -
----------------------------------------------------------------------------
Net income (loss) from continuing
operations $ 11,368 $ (115,955) -
Net income from discontinued operations
(USOGP) 146,024 146,389 -
----------------------------------------------------------------------------
Consolidated net income $ 157,392 $ 30,434 417
----------------------------------------------------------------------------
----------------------------------------------------------------------------


Net income for the year ended December 31, 2008 increased to $157.4 million compared to $30.4 million of net income in 2007. On a consolidated basis, the increase in net income in 2008 was driven by favorable operating results compared to 2007 as well as a $435.7 million change to unrealized gain (loss) on financial derivative instruments, partially offset by a $416.9 million non-cash goodwill impairment charge (see "Goodwill").

The Provident Upstream business segment's net loss was $306.0 million, a $351.0 million decrease compared with year ended December 31, 2007 net income of $45.0 million. A $131.7 million increase in EBITDA and a $51.5 million increase in unrealized gains on financial derivative instruments were more than offset by a non-cash goodwill impairment charge of $416.9 million and, to a lesser extent, increased depletion, depreciation and accretion (DD&A) and a decrease in future income tax recoveries.

The Provident Midstream segment recorded net income of $317.4 million as compared to a net loss of $161.0 million in the year ended December 31, 2007. In 2008, Provident Midstream generated a $14.5 million, or four percent increase in gross operating margin over 2007, reflecting the positive price environment in the first nine months of the year and a $23.8 million increase over 2007 in foreign exchange gains on U.S. dollar based transactions. These increases were offset by a $44.4 million increase in realized losses on financial derivative instruments. However, the income was primarily attributable to the requirement under generally accepted accounting principles (GAAP) 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. In 2008, this resulted in $191.2 million of additional income before future income taxes compared to a $192.9 million reduction in income before future income taxes in 2007, representing a $384.2 million swing in unrealized gains on financial derivative instruments over the two year period. Because Provident's commodity price risk management program involves the use of financial derivative instruments with terms that extend up to five years into the future in the Midstream segment, net earnings can show substantial variation that is not necessarily related to current operations. In addition, a $73.7 million decrease in future tax expense contributed to the increase in Provident Midstream net income.

Net income from discontinued operations (USOGP) in 2008 was $146.0 million as compared to $146.4 million in 2007. The 2008 net income is primarily driven by gains on sale of the discontinued operations, amounting to $263.6 million. Net income from discontinued operations in 2007 included a dilution gain of $260.3 million recognized as MLP units were issued to third parties to finance growth.

Reconciliation of non-GAAP measures

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



Year ended December 31,
----------------------------------------------------------------------------
($ 000s) 2008 2007 % Change
----------------------------------------------------------------------------
EBITDA $ 566,254 $ 447,427 27
Adjusted for:
Cash interest (50,793) (54,181) (6)
Unrealized gain (loss) on financial
derivative instruments 221,468 (214,244) -
Goodwill impairment (416,890) - -
Depletion, depreciation and accretion
and other non-cash expenses (339,856) (313,199) 9
----------------------------------------------------------------------------
Loss from continuing operations before
taxes $ (19,817) $ (134,197) (85)
----------------------------------------------------------------------------
----------------------------------------------------------------------------


The following table reconciles funds flow from operations with cash provided
by operating activities and distributions to unitholders:

Reconciliation of funds flow
from operations to distributions Year ended December 31,
----------------------------------------------------------------------------
($ 000s, except per unit data) 2008 2007 % Change
----------------------------------------------------------------------------
Cash provided by operating activities $ 674,426 $ 464,455 45
Change in non-cash operating working
capital (25,650) (262) 9,690
Site restoration expenditures 6,381 4,062 57
----------------------------------------------------------------------------
Funds flow from operations 655,157 468,255 40
Distributions to non-controlling
interests (51,433) (35,846) 43
Cash retained for financing and
investing activities (251,433) (99,057) 154
----------------------------------------------------------------------------
Distributions to unitholders 352,291 333,352 6
Accumulated cash distributions,
beginning of year 1,260,177 926,825 36
----------------------------------------------------------------------------
Accumulated cash distributions,
end of year $1,612,468 $1,260,177 28
----------------------------------------------------------------------------
Cash distributions per unit $ 1.38 $ 1.44 (4)
----------------------------------------------------------------------------
----------------------------------------------------------------------------


Taxes

Year ended December 31,
----------------------------------------------------------------------------
($ 000s) 2008 2007 % Change
----------------------------------------------------------------------------
Capital tax expense $ 3,109 $ 3,762 (17)
Current and withholding tax
(recovery) expense (4,529) 6,352 -
Future income tax recovery (29,765) (28,356) 5
----------------------------------------------------------------------------
$(31,185) $(18,242) 71
----------------------------------------------------------------------------
----------------------------------------------------------------------------


Capital taxes in 2008 totaled $3.1 million, a decrease from the $3.8 million expense recorded in 2007. The decrease reflects upward adjustments made in 2007 upon filing of previous years tax returns.

The current and withholding tax recovery of $4.5 million in 2008 compares to $6.4 million expense in 2007. The decrease in current taxes was due to lower income subject to tax in the U.S.-based Midstream operations.

For the year ended December 31, 2008, future income tax recovery was $29.8 million, compared with a recovery of $28.4 million in 2007. In 2008, additional future tax recoveries were recorded as a result of an internal structural reorganization as well as losses created by interest and royalty deductions at the incorporated subsidiary level, offset by future tax expense relating to unrealized gains on financial derivative instruments. The goodwill impairment charge in 2008 had no impact on future income taxes. The 2007 future income tax recovery includes $88.4 million of expense relating to the enactment of legislation to tax publicly traded trusts in 2011 offset by future tax recoveries created by interest and royalty deductions at the incorporated subsidiary level.

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

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

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

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

The Trust has approximately $1.4 billion in tax pools available to claim against taxable income. Provident plans to manage discretionary tax pool claims to defer payment of current taxes as long as possible. Provident has made estimates of taxability in future years based on a number of assumptions including: future product prices; future production and sales; future operating and product costs; future general and administrative costs; future capital expenditures; and general business conditions. Using these assumptions about future events which may or may not occur, Provident estimates that:

- current taxes on Canadian oil and gas operations would occur after 2016; and

- current taxes for midstream operations would occur in 2011.

Provident's tax pools available to shelter future income as at December 31, 2008 are estimated as follows:




As at December 31, 2008
----------------------------------------------------------------------------
Provident Provident
($ 000s) Upstream Midstream Total
----------------------------------------------------------------------------
Intangibles $ 610,000 $ - $ 610,000
Tangibles 265,000 270,000 535,000
Non-capital losses 260,000 10,000 270,000
----------------------------------------------------------------------------
$1,135,000 $ 280,000 $1,415,000
----------------------------------------------------------------------------
----------------------------------------------------------------------------


Provident also has capital losses of approximately $370 million which are
available to reduce the tax effect of future capital gains.

Interest expense

Continuing operations Year ended December 31,
----------------------------------------------------------------------------
($ 000s, except as noted) 2008 2007 % Change
----------------------------------------------------------------------------

Interest on bank debt $ 35,044 $ 42,477 (17)
Interest on convertible debentures 19,934 20,200 (1)
Discontinued operations portion (4,185) (8,496) (51)
----------------------------------------------------------------------------
Total cash interest $ 50,793 $ 54,181 (6)
----------------------------------------------------------------------------
----------------------------------------------------------------------------

Weighted average interest rate on
all long-term debt 5.3% 5.8% (9)

Debenture accretion and other non-cash
interest expense 5,239 4,727 11
----------------------------------------------------------------------------
Total interest expense $ 56,032 $ 58,908 (5)
----------------------------------------------------------------------------
----------------------------------------------------------------------------


Interest expense decreased in 2008 compared to 2007 due to lower debt levels and lower market interest rates. Cash proceeds on the sale of USOGP in June and August of 2008, amounting to $457.9 million, net of tax, were used to pay down debt.

Financial instruments

Commodity price risk management program

For the year ended December 31, 2008 $130.0 million was recorded as a realized loss on financial derivative instruments due to the Commodity Price Risk Management Program (the Program) with $11.1 million related to Provident Upstream and $118.9 million associated with the Provident Midstream segment.

In the Provident Upstream segment, the realized loss in 2008 associated with crude oil and natural gas liquids totaled $11.1 million ($2.22 per barrel) and a realized gain of nil related to natural gas. The combined total was a loss of $11.1 million or $1.10 per boe. In 2007 the Program recorded a realized loss of $7.9 million related to crude oil and natural gas liquids ($1.95 per barrel) and a realized gain of $9.6 million related to natural gas ($0.28 per mcf). The combined 2007 total was a gain of $1.7 million, or $0.18 per boe.

In 2008 the Midstream segment recorded realized losses on crude oil contracts amounting to $135.6 million (2007 - gains of $17.9 million), and realized losses of $17.0 million (2007 - $48.7 million) related to natural gas. In addition, realized gains associated with NGL market based contracts totaled $25.9 million (2007 - losses of $48.2 million), realized gains on Midstream-related foreign exchange contracts were $5.4 million (2007 - $4.6 million) and realized gains on electricity-based contracts were $2.4 million (2007 - nil).

Realized gains on corporate-related foreign exchange contracts in 2008 related to the Program were $26.8 million (2007 - $1.3 million). Realized gains and losses on corporate-related foreign exchange contracts are included in foreign exchange (gain) loss and other on the consolidated statement of operations and are allocated to the reporting segments for segmented reporting purposes. The gain in 2008 relates primarily to contracts put in place to mitigate the foreign exchange risk associated with U.S.-denominated taxes payable in connection with the sale of discontinued operations (USOGP).

On a per trust unit basis the opportunity cost of the Program increased to $0.51 per trust unit in 2008 from $0.32 per trust unit in 2007. The increased per unit cost in 2008 was more than offset by the funds flow from operations generated by the business units in the high commodity price environment and is reflected in the 26 percent increase in funds flow operations on a per unit basis. In the fourth quarter of 2008, when commodity prices dropped dramatically, the Program helped to stabilize cash flow by contributing $24.3 million, or 30 percent of fourth quarter funds flow from operations.

At December 31, 2008 the mark-to-market value of open contracts was in a net loss position of $54.7 million based upon commodity prices prevailing at that date. Under generally accepted accounting principles, these unrealized "mark-to-market" opportunity costs, which relate to financial derivative positions with effective periods ranging from January 2009 through March 2013, are required to be recognized in the financial statements of Provident, affecting current period net income. Fluctuations in the market value of these instruments have no impact on cash flow until the instruments are settled.

Provident's commodity price risk management program utilizes derivative instruments to provide insurance against lower commodity prices and margins. The program provides support for 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 while, with some products, allowing the Trust to participate in a rising commodity price environment. It provides price stabilization and protection of a percentage of inventory values and fractionation spread margin associated with the Midstream 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.

Management believes that financial markets currently provide adequate liquidity through price discovery and active credit-worthy counterparties for Provident to continue to execute the program in 2009. The derivative instruments the Trust uses include puts, calls, 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.

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

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

Based on their evaluation as of December 31, 2008, Provident's chief executive officer and chief financial officer concluded that Provident's disclosure controls and procedures (as defined in Rules 13(a)-15(e) and 15(d)-15(e) under the United States Securities Exchange Act of 1934 (the Exchange Act) are effective to ensure that information required to be disclosed by Provident in reports that it files or submits under the Exchange Act is recorded, processed, summarized and reported within the time periods specified in the United States Securities and Exchange Commission rules and forms. In addition, as of December 31, 2008, there were no changes in Provident's internal controls over financial reporting that occurred during 2008 that have materially affected, or are reasonably likely to materially affect its internal controls over financial reporting.

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

The Trust has undertaken a comprehensive review of the effectiveness of its internal control over financial reporting as part of the reporting, certification and attestation requirements of Section 404 of the U.S. Sarbanes-Oxley Act of 2002. For the year ended December 31, 2008 the company's internal controls were found to be operating free of any material weaknesses.

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, 2007 Goodwill was comprised of $416.9 million related to acquisitions in the Canadian oil and gas business and $100.4 million resulted from the Midstream NGL Acquisition in 2005.

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 2008, 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 2008 and determined that the fair value of the Canadian oil and gas production unit was lower than the respective carrying value, primarily due to increasing economic uncertainty in the global market and the resulting higher cost of capital assumptions in the valuation methodologies. Consequently, a goodwill impairment, amounting to $416.9 million was recorded. The impairment test indicated that the fair value of the Midstream reporting unit was in excess of the respective carrying value, therefore no write down of midstream-related goodwill was required. At December 31, 2008 the goodwill balance of $100.4 million is related entirely to the Provident Midstream reporting unit.



Liquidity and capital resources

Continuing operations As at December 31,
----------------------------------------------------------------------------
($ 000s) 2008 2007 % Change
----------------------------------------------------------------------------

Long-term debt - revolving term credit
facility $ 504,685 $ 923,996 (45)
Long-term debt - convertible
debentures
(including current portion) 260,994 275,638 (5)
Working capital surplus (1) (39,041) (58,732) (34)
----------------------------------------------------------------------------
Net debt $ 726,638 $ 1,140,902 (36)
----------------------------------------------------------------------------

Unitholders' equity (at book value) 1,636,347 1,708,665 (4)
----------------------------------------------------------------------------
Total capitalization at book value $ 2,362,985 $ 2,849,567 (17)
----------------------------------------------------------------------------
----------------------------------------------------------------------------

Total net debt as a percentage of
total book value capitalization 31% 40% (23)
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(1) The working capital surplus excludes balances for the current portion of
financial derivative instruments.


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 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, oil and gas industry participants, including Provident, are experiencing more restricted access to capital and anticipate increased borrowing costs. Although Provident's business and asset base have not changed, the lending capacity of financial institutions has been diminished and risk premiums have increased. Management continues to believe that cash flows from operating activities and availability under existing bank facilities will be adequate to allow Provident to move forward with its 2009 capital program. However, these issues will affect Provident as it reviews financing alternatives for future capital expenditures and potential acquisition opportunities in the current lower commodity price environment.

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. The carrying value of accounts receivable reflects management's assessment of the associated credit risks.

As at December 31, 2008, Provident held non-bank sponsored asset-backed commercial paper with a face value of $6.1 million. Provident has recorded an impairment write-down amounting to $4.3 million in 2008 (2007 - $1.8 million) to reflect the fair value of these assets at December 31, 2008, determined to be nil. The write-down is included in net income as part of foreign exchange (gain) loss and other.



Contractual obligations

Consolidated Payment due by period
----------------------------------------------------------------------------
Less More
than 1 1 to 3 4 to 5 than 5
($ millions) Total year years years years
----------------------------------------------------------------------------

Long-term debt -
revolving term credit
facility (1) (3) $ 548.8 $ 16.8 $ 532.0 $ - $ -
Long-term debt -
convertible debentures
(2) (3) 321.6 42.5 175.8 103.3 -
Operating lease
obligations 195.6 22.3 37.6 29.1 106.6
----------------------------------------------------------------------------
Total $ 1,066.0 $ 81.6 $ 745.4 $ 132.4 $ 106.6
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(1) The terms of the Canadian credit facility have a revolving three year
period expiring on May 30, 2011.
(2) Includes current portion of convertible debentures.
(3) Includes associated interest and principal payments.


Long-term debt and working capital

As at December 31, 2008 Provident had drawn on 45 percent of its term credit facility of $1,125 million as compared to 81 percent drawn as at December 31, 2007. The decrease in the level of bank debt reflects the application of $457.9 million of cash proceeds, net of tax, realized on the disposition of USOGP. During 2008, capital expenditures and distributions to unitholders were roughly equivalent with the sum of funds flow from operations, DRIP proceeds and changes in working capital.

At December 31, 2008 Provident had letters of credit guaranteeing Provident's performance under certain commercial and other contracts that totaled $35.2 million, increasing bank line utilization to 48 percent. The guarantees at December 31, 2007 totaled $31.6 million.

Provident's working capital from continuing operations increased by $106.6 million from a deficit of $89.4 million to a surplus of $17.2 million as at December 31, 2008. The significant increase is primarily due to a $132.0 million decrease in net current financial derivative instrument liabilities, a $103.2 million decrease in accounts payable and accrued liabilities, partially offset by decreased accounts receivable of $93.6 million and a $38.5 million decrease in inventory.

The ratio of net debt (as calculated under "Liquidity and capital resources") to funds flow from continuing operations in 2008 was 1.4 to one, compared to 3.0 to one in 2007. The decrease reflects a decrease in net debt as well as higher funds flow from operations. On a segmented basis, the Provident Upstream business had a ratio of net debt to funds flow from operations in 2008 of 0.7 to one (2007 - 1.8 to one). The ratio for the Provident Midstream business unit was 2.7 to one in 2008, compared to 4.3 to one in 2007.

Trust units

For the year ended December 31, 2008 the Trust issued six thousand units on conversion of convertible debentures (2007 - 0.5 million units). An additional 0.2 million units were issued pursuant to the unit option plan for the year ended December 31, 2008 (2007 - 0.8 million units). Under Provident's Premium Distribution, Distribution Reinvestment (DRIP) and Optional Unit Purchase Plan program 6.3 million units were issued or are to be issued in 2008 representing proceeds of $53.8 million (2007 - 4.5 million units for proceeds of $50.5 million).

At December 31, 2008 management and directors held less than one percent of the outstanding trust units.



Capital expenditures and funding

Continuing operations Year ended December 31,
----------------------------------------------------------------------------
($ 000s) 2008 2007 % Change
----------------------------------------------------------------------------
Capital Expenditures
Capital expenditures and site
restoration expenditures $ (253,328) $ (182,175) 39
Property acquisitions, net (24,181) (13,050)
Corporate acquisitions - (469,795)
----------------------------------------------------------------------------
Net capital expenditures $ (277,509) $ (665,020) (58)
----------------------------------------------------------------------------

Funded By
Funds flow from continuing operations
net of declared distributions to
unitholders $ 165,331 $ 49,332 235
Proceeds on sale of discontinued
operations, net of tax 457,906 - -
(Decrease) increase in long-term debt (440,244) 169,122 -
Issue of trust units, net of cost;
excluding DRIP 1,672 362,418 (100)
DRIP proceeds 53,838 50,491 7
Change in working capital, including
cash, sale of assets and change in
investments 39,006 33,657 16
----------------------------------------------------------------------------
Net capital expenditure funding $ 277,509 $ 665,020 (58)
----------------------------------------------------------------------------
----------------------------------------------------------------------------


Net capital expenditures were funded by a combination of funds flow from operations, debt, equity issued from treasury through public offerings, the DRIP program and proceeds on the sale of discontinued operations.

Non-cash unit based compensation

Non-cash unit based compensation includes expenses or recoveries associated with Provident's restricted and performance unit plan as well as the unit option plan. Provident accounts for the unit option plan using the fair value of the option at the time of issue. The other unit based compensation is recorded at the estimated fair value of the notional units granted. Compensation expense associated with the plans is recognized in earnings over the vesting period of each plan. The expense 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, 2008, Provident recorded unit based compensation expense of $4.4 million (2007 - $10.2 million) and made related cash payments of $8.3 million (2007 - $1.8 million). The expense is lower in 2008 as a result of a lower Provident trust unit trading price, upon which the compensation is based. At December 31, 2008, the current portion of the liability totaled $9.4 million (December 31, 2007 - $9.9 million) and the long-term portion totaled $8.6 million (December 31, 2007 - $12.4 million).



Provident Upstream segment review

Crude oil and natural gas liquids prices

Provident Upstream Year ended December 31,
----------------------------------------------------------------------------
($ per bbl) 2008 2007 % Change
----------------------------------------------------------------------------

Oil per barrel
WTI (US$) $ 99.65 $ 72.31 38
Exchange rate (from US$ to Cdn$) $ 1.07 $ 1.07 -
WTI expressed in Cdn$ $ 106.33 $ 77.67 37
----------------------------------------------------------------------------
----------------------------------------------------------------------------

Realized pricing before financial
derivative instruments
Crude oil $ 82.79 $ 56.74 46
Natural gas liquids $ 76.88 $ 55.07 40
----------------------------------------------------------------------------
Crude oil and natural gas liquids $ 82.27 $ 56.54 46
----------------------------------------------------------------------------
----------------------------------------------------------------------------


The above realized prices are net of transportation expense.

For the year ended December 31, 2008 Provident's realized crude oil and natural gas liquids price, prior to the impact of financial derivative instruments, increased by 46 percent to average $82.27 compared to $56.54 in 2007. The 2008 increase related to a 38 percent higher US$ WTI crude oil price and narrower pricing differentials on crude oil streams.



Natural gas price

Provident Upstream Year ended December 31,
----------------------------------------------------------------------------
($ per mcf) 2008 2007 % Change
----------------------------------------------------------------------------

AECO monthly index (Cdn$ per mcf) $ 8.12 $ 6.59 23
Corporate natural gas price per mcf before
financial derivative instruments (Cdn$) $ 8.23 $ 6.42 28
----------------------------------------------------------------------------


The above prices are net of transportation expense.

For the year ended December 31, 2008 Provident's realized natural gas price, excluding financial derivative instruments, increased 28 percent as compared to 2007, greater than the increase 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

Provident Upstream Year ended December 31,
----------------------------------------------------------------------------
2008 2007 % Change
----------------------------------------------------------------------------
Daily production
Crude oil (bpd) 12,473 9,797 27
Natural gas liquids (bpd) 1,203 1,316 (9)
Natural gas (mcfd) 84,039 92,378 (9)
----------------------------------------------------------------------------
Oil equivalent (boed) (1) 27,683 26,509 4
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(1) Provident reports equivalent production converting natural gas to oil on
a 6:1 basis.


For the year ended December 31, 2008, Provident Upstream production averaged 27,683 boed, a four percent increase compared to 26,509 boed in 2007. The increase is primarily a result of the full year effect in 2008 of the two acquisitions, Capitol in June of 2007 and Triwest in December of 2007, the additional working interests acquired throughout 2008, and the production volumes added through drilling and optimization activities, partially offset by production declines typical in the Western Canadian Sedimentary Basin. The Capitol acquisition became Provident Upstream's newest core area, Dixonville, and the Triwest acquisition is included in the Southeast Saskatchewan core area.

Production for 2008 was weighted 51 percent natural gas and 49 percent crude oil and natural gas liquids. This compared to 2007 production weighted 58 percent natural gas and 42 percent crude oil and natural gas liquids. Year-over-year, the change in mix reflects the full year effect for 2008 of the two acquisitions in 2007 which were primarily light/medium crude oil production.



Provident Upstream production summarized by core areas is as follows:

Year ended December 31,
----------------------------------------------------------------------------
Provident Upstream 2008 2007 % Change
----------------------------------------------------------------------------
Daily Production - by area (boed) (1)
West Central Alberta 6,271 7,011 (11)
Southern Alberta 4,883 5,622 (13)
Northwest Alberta 4,690 4,905 (4)
Dixonville (2) 3,764 2,058 83
Southeast Saskatchewan 3,061 1,769 73
Southwest Saskatchewan 1,333 1,726 (23)
Lloydminster 3,681 3,418 8
----------------------------------------------------------------------------
27,683 26,509 4
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(1) Provident reports equivalent production converting natural gas to oil
on a 6:1 basis.
(2) Dixonville production in 2007 represents production from June 19, 2007
(date of Capitol Energy Resources Ltd. acquisition) amounting to 3,852
boed for the 195 days.


Revenue and royalties

Provident Upstream Year ended December 31,
----------------------------------------------------------------------------
($ 000s except per boe and mcf data) 2008 2007 % Change
----------------------------------------------------------------------------

Oil
Revenue $ 377,976 $ 202,909 86
Realized loss on financial derivative
instruments (11,113) (7,905) 41
Royalties (69,897) (39,211) 78
----------------------------------------------------------------------------
Net revenue $ 296,966 $ 155,793 91
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Net revenue (per barrel) $ 65.05 $ 43.57 49
Royalties as a percentage of revenue 18.5% 19.3%

Natural gas
Revenue $ 253,183 $ 216,626 17
Realized gain on financial derivative
instruments 11 9,633 (100)
Royalties (44,715) (41,154) 9
----------------------------------------------------------------------------
Net revenue $ 208,479 $ 185,105 13
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Net revenue (per mcf) $ 6.78 $ 5.49 23
Royalties as a percentage of revenue 17.7% 19.0%

Natural gas liquids
Revenue $ 33,857 $ 26,451 28
Royalties (8,528) (6,681) 28
----------------------------------------------------------------------------
Net revenue $ 25,329 $ 19,770 28
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Net revenue (per barrel) $ 57.53 $ 41.16 40
Royalties as a percentage of revenue 25.2% 25.3%

Total
Revenue $ 665,016 $ 445,986 49
Realized (loss) gain on financial
derivative instruments (11,102) 1,728 -
Royalties (123,140) (87,046) 41
----------------------------------------------------------------------------
Net revenue $ 530,774 $ 360,668 47
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Net revenue (per boe) $ 52.39 $ 37.27 41
Royalties as a percentage of revenue 18.5% 19.5%
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Note: the above revenue, net revenue and net revenue per boe figures are
presented net of transportation expenses.


For the year ended December 31, 2008 Provident Upstream production revenue was $665.0 million, an increase of 49 percent from $446.0 million in 2007. The increase in revenue was a result of the four percent increase in production and higher realized crude oil, natural gas liquids, and natural gas prices. Royalties as a percentage of revenue had a slight decrease to 18.5 percent reflecting capital expenditures on gas facilities. The preceding factors offset by the $11.1 million realized loss on financial derivative instruments compared to a $1.7 million realized gain in 2007, account for net revenue of $530.8 million in 2008, 47 percent higher than the $360.7 million recorded in 2007.

Net revenue per boe in 2008 increased 41 percent to $52.39 from $37.27 in 2007 resulting primarily from higher realized crude oil, natural gas liquids, and natural gas prices and a higher percentage of production from crude oil and natural gas liquids.



Production expense

Provident Upstream Year ended December 31,
----------------------------------------------------------------------------
($ 000s, except per boe data) 2008 2007 % Change
----------------------------------------------------------------------------

Production expenses $ 138,173 $ 112,387 23
Production expenses (per boe) $ 13.64 $ 11.62 17
----------------------------------------------------------------------------
----------------------------------------------------------------------------


For the year ended December 31, 2008 production expenses increased 23 percent to $138.2 million from $112.4 million and increased by 17 percent on a per boe basis to $13.64 per boe from $11.62 per boe in the prior year. The increase in total costs was due to the four percent increase in production combined with returning higher operating cost wells to production in the second and third quarters of 2008 to take advantage of record crude oil prices and associated netbacks. The increased commodity prices resulted in high prices for fuel and power and high industry activity levels in the second and third quarters of 2008 resulted in increased costs for service related activities for down-hole and maintenance work. The wells returned to production included higher operating costs for fluid hauling, and associated maintenance and down-hole costs. In addition, colder weather in the first and fourth quarters of 2008 impacted operations and unscheduled turnarounds in Northwest Alberta were performed in the fourth quarter of 2008 to take advantage of circumstances resulting from a third-party pipeline outage.



Operating netback

Provident Upstream Year ended December 31,
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($ per boe) 2008 2007 % Change
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Netback per boe
Gross production revenue $ 65.64 $ 46.09 42
Royalties (12.15) (9.00) 35
Operating costs (13.64) (11.62) 17
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Field operating netback 39.85 25.47 56
Realized (loss) gain on financial
derivative instruments (1.10) 0.18 -
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Operating netback after realized
financial derivative instruments $ 38.75 $ 25.65 51
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Provident Upstream operating netbacks have transportation expense netted against gross production revenue.

The 2008 field operating netback of $39.85 per boe was 56 percent above the $25.47 per boe for the prior year. This reflects increased realized crude oil, natural gas liquids, and natural gas prices and an increase in Provident's production mix of crude oil and natural gas liquids to 49 percent in 2008 from 42 percent in 2007. This was partially offset by 17 percent higher operating costs per boe. Royalties, which are price sensitive, increased by 35 percent on a boe basis reflecting the higher commodity prices. The 2008 operating netbacks after financial derivative instruments increased by 51 percent to $38.75 from $25.65 in the prior year due to the preceding factors as well as the realized loss on financial derivative instruments of $1.10 per boe compared to $0.18 per boe realized gain in the prior year.



General and administrative

Provident Upstream Year ended December 31,
----------------------------------------------------------------------------
($ 000s, except per boe data) 2008 2007 % Change
----------------------------------------------------------------------------

Cash general and administrative $ 36,191 $ 27,102 34
Non-cash unit based compensation (2,199) 3,698 -
----------------------------------------------------------------------------
$ 33,992 $ 30,800 10

Cash general and administrative (per boe) $ 3.57 $ 2.80 28
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For the year ended December 31, 2008, cash general and administrative expenses were $36.2 million (2007 - $27.1 million), an increase of 34 percent. On a boe basis, cash general and administrative expenses in 2008 increased 28 percent to $3.57 per boe from $2.80 per boe in 2007. The 2008 cash general and administrative expenses included $4.5 million, or $0.45 per boe (2007 - $0.9 million or $0.09 per boe) related to payments associated with unit based compensation. The unit based expense was accrued over a three-year vesting period as non-cash unit based compensation, consequently, there is an offsetting reduction in non-cash unit based compensation when the payments are made. Excluding these payments, cash general and administrative expenses were $31.7 million, or $3.12 per boe (2007 - $26.2 million or $2.71 per boe). The increase reflects higher office-related expenses, particularly rent, and costs associated with the previously announced strategic evaluation of Provident's business units, including an internal structural reorganization completed in the fourth quarter of 2008.

Non-cash unit based compensation was a recovery of $2.2 million in 2008 and an expense of $3.7 million in 2007. Excluding the related cash payments in each year, non-cash unit based compensation was an expense of $2.3 million in 2008 (2007 - $4.6 million). Non-cash unit based compensation is lower in 2008 as a result of a lower Provident trust unit trading price, upon which the compensation is based.



Capital expenditures

Provident Upstream Year ended December 31,
----------------------------------------------------------------------------
($ 000s) 2008 2007
----------------------------------------------------------------------------

Capital expenditures - by category
Geological, geophysical and land $ 25,474 $ 4,519
Drilling and recompletions 146,992 113,425
Facilities and equipment 34,514 13,378
Office and other 2,167 14,887
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Total additions $ 209,147 $ 146,209
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Capital expenditures - by area
West central Alberta $ 10,326 $ 9,051
Southern Alberta 19,852 13,079
Northwest Alberta 79,445 35,993
Dixonville 60,339 43,801
Southeast Saskatchewan 21,175 5,069
Southwest Saskatchewan 5,369 15,196
Lloydminster 8,181 9,235
Other 4,460 14,785
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Total additions $ 209,147 $ 146,209
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Property acquisitions, net $ 24,181 $ 13,050
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In 2008, Provident's Upstream business unit spent $207.0 million on capital expenditures before office and other capital costs. Internal development activities included 87.4 net wells drilled for the year ended December 31, 2008 with a 99 percent success rate. Provident's drilling activities in 2008 were more focused on crude oil compared to 2007. Provident spent $79.4 million in Northwest Alberta, primarily on drilling and completion activities which included 14.0 net wells drilled, the infrastructure and tie-in activities associated with the 2007/2008 winter drilling program and preparation work to start the 2008/2009 winter drilling program. Facility and pipeline work in Northwest Alberta included preparation work to develop the emerging Pekisko opportunity and 95.4 net sections (approximately 61,000 acres) of land were also acquired for the Pekisko opportunity. Provident spent $60.3 million in the newest core area, Dixonville, primarily on drilling and completion activities which resulted in 41.0 net wells drilled. In the Southeast Saskatchewan core area, $21.2 million was spent which included 13.8 net wells drilled. As oil prices increased during the first half of 2008, capital work was primarily focused on oil drilling in Dixonville and primarily light oil drilling in Southeast Saskatchewan. The shallow gas drilling program in Southwest Saskatchewan was reduced. In Southern Alberta, $19.9 million was primarily spent on drilling activity and recompletions, which included 14.1 net wells drilled, and on facility upgrades and infrastructure work. The $26.2 million of capital spent in the remaining core areas included drilling, completion, tie-ins, recompletions, facility upgrades and production optimization activities.

Additions to proved plus probable reserves (before revisions) through internal capital replaced approximately 70 percent of annual production.

In 2008, Provident also spent $24.2 million on property acquisitions primarily on acquiring additional working interests in Northwest Alberta and Southern Alberta.



Depletion, depreciation and accretion (DD&A)

Provident Upstream Year ended December 31,
----------------------------------------------------------------------------
($ 000s, except per boe data) 2008 2007 % Change
----------------------------------------------------------------------------

DD&A $ 304,909 $ 256,723 19
DD&A (per boe) $ 30.09 $ 26.53 13
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----------------------------------------------------------------------------


The Provident Upstream DD&A rate of $30.09 per boe increased 13 percent for 2008 compared to $26.53 per boe in 2007. The increase was partly as a result of the two acquisitions of Capitol and Triwest in 2007. In addition, 2008 expenditures on geological, geophysical, land and facilities added to costs to be depleted without directly adding proved reserves. The recent Upstream acquisitions and the Rainbow assets acquired in 2006 differed from earlier acquisitions in that they included significant reserves that were not yet proved. Since depletion calculations are based on proved reserves, acquisitions with unproved reserves generally result in higher depletion rates. The impact of this, combined with the higher cost of acquiring or drilling proved reserves in western Canada in an environment with higher commodity prices and increased drilling costs, will be reflected in the DD&A rate going forward.

In 2008, DD&A also includes accretion expense associated with asset retirement obligation of $3.4 million (2007 - $2.5 million).

As part of the reconciliation of Provident's financial statements to United States generally accepted accounting principles (U.S. GAAP), disclosed in note 18 to the consolidated financial statements, the Trust has reflected additional depletion in 2008 of $814.0 million (2007 - $181.6 million) and a related future income tax recovery of $214.3 million (2007 - $52.2 million) as a result of the application of the U.S. GAAP ceiling test. These charges were not required under Canadian generally accepted accounting principles.

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

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

- 50 percent ownership in the 130,000 bpd Kerrobert pipeline and 2.5 mmbbl underground storage facility near Kerrobert, Saskatchewan which facilitates injection into the Enbridge pipeline system. Along the Enbridge pipeline system in Superior, Wisconsin, Provident holds an 18.3 percent ownership of a 300,000 barrel storage staging facility and 18.3 percent ownership of the 6,600 bpd depropanizer.

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

- A propane distribution terminal at Lynchburg, Virginia.

- A rail car fleet of approximately 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, six million gross barrels of salt cavern storage, and a 60,000 bpd condensate rail offloading facility with a 300 railcar storage yard. The facility can process high-sulphur NGL streams and is one of only two ethane-plus fractionation facilities in western Canada capable of extracting ethane from the natural gas liquids stream.

- In 2009, two new caverns (approximately 500,000 barrels each) will be brought into service and are planned to be used for condensate storage.

- 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 Commercial Services business line:

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

Long term contracts

At the Redwater 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.

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

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

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



The 2008 Provident Midstream business unit results can be summarized as
follows:

Year ended December 31,
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($ 000s) 2008 2007 % Change
----------------------------------------------------------------------------

Empress East Margin $ 157,976 $ 183,565 (14)
Redwater West Margin 142,836 94,600 51
Commercial Services Margin 46,541 54,649 (15)
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Gross operating margin 347,353 332,814 4
Realized loss on financial
derivative instruments (118,917) (74,474) 60
Cash general and administrative
expenses (35,528) (28,669) 24
Foreign exchange gain (loss) and other 19,853 (3,996) -
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Provident Midstream EBITDA $ 212,761 $ 225,675 (6)
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Gross operating margin

The Empress East business line extracts NGLs from natural gas at the Empress straddle plants and sells finished products into markets in Central Canada and the Eastern United States. The margin in this business is determined primarily by the "frac spread ratio", which is the ratio between crude oil prices and natural gas prices. The higher the ratio, the better this business line will perform. There is also a differential between propane, butane and condensate (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 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 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 2008 gross operating margin from Empress East was $158.0 million compared to $183.6 million in 2007. The decrease reflects approximately 18 percent higher propane-plus prices offset by 29 percent higher propane-plus costs as a result of a significant increase in gas prices in 2008. Frac spread ratios during the first nine months of 2008 averaged 14.3, compared to 11.6 during the same period in 2007. However, frac spread ratios reversed in the fourth quarter of 2008 averaging 11.2, compared to 15.7 during the fourth quarter of 2007. In addition, 2008 experienced a significant decline in the sales price of propane relative to the price of crude oil. Posted prices at Mont Belvieu for propane in 2008 averaged 60 percent of WTI, compared to 70 percent in 2007. Overall strong performance in the first three quarters of 2008 was offset in the fourth quarter by higher cost inventory built up in the second and third quarters at historically high product prices, then subsequently sold in the fourth quarter, when product prices had dropped significantly.

Subsequent to year end, conditions have shown some improvement. The frac spread ratio in January 2009 has improved by nine percent compared to December, and the price of propane as a percentage of WTI has increased to 72 percent.

The Redwater West business line purchases an NGL mix from various producers and fractionates it into finished products at the Redwater fractionation facility near Edmonton, Alberta. Because the feedstock for this business line is primarily NGL mix rather than natural gas, the frac spread ratio has a smaller impact on margin than in the Empress East business line. 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 participation in the condensate market over the past year, reflecting the increased demand for condensate as diluent for heavy oil production.

In 2008, the operating margin for the Redwater West business line was $142.8 million (2007 - $94.6 million). The 51 percent increase in margin was driven by a 15 percent increase in propane-plus sales volumes, primarily condensate, and a 26 percent increase in propane-plus prices versus a 25 percent increase in costs.

The Commercial Services business line generates income from stable fee-for-service contracts to provide fractionation, storage, loading, and marketing services to upstream producers. Income from pipeline tariffs from Provident's ownership in NGL pipelines is also included in this business line. In 2008, the margin for this business line was $46.5 million (2007 - $54.6 million). In 2008, while the margin for this business line was 15 percent lower, it does include a 46 percent increase in fees associated with our offloading terminal, due to increased condensate business. In 2007, the Commercial Services margin included payments received for product quality adjustments at our condensate offloading facility. These payments increased operating margin in 2007, are generally non-recurring and account for the year over year decrease in operating margin.

Operations - Provident Midstream NGL sales volumes

Provident Midstream sold 119,649 bpd in 2008, compared with 120,785 in 2007. Higher propane-plus volumes were offset by lower ethane volumes reflecting reduced demand in the fourth quarter of 2008.

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

For 2008, Provident Midstream EBITDA decreased $12.9 million or six percent from $225.7 million in 2007. A $14.5 million increase in gross operating margin as described above, as well as foreign exchange gains on U.S. dollar-based transactions, were tempered by a $44.4 million increase in realized losses on financial derivative instruments and higher cash general and administrative and other costs. Funds flow from operations for 2008 was $179.0 million, an increase of $0.6 million above the $178.4 million in 2007. The increase in funds flow from operations reflects the lower EBITDA being more than offset by reduced interest charges and a current tax recovery.

Cash general and administrative expenses and other were $35.5 million for 2008 (2007- $28.7 million). Included in this amount is $3.8 million (2007 - $0.9 million) related to payments associated with unit based compensation. The expense was accrued over a three-year vesting period as non-cash unit based compensation, consequently there is an offsetting reduction in non-cash unit based compensation when the payments are made. Excluding these payments, cash general and administrative expenses were $31.7 million in 2008 (2007 - $27.8 million). The increase reflects higher office-related expenses, particularly rent, and costs associated with the previously announced strategic evaluation of Provident's business units, including an internal structural reorganization completed in the fourth quarter of 2008.

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

Capital expenditures

Provident Midstream capital expenditures in 2008 totaled $37.8 million. In 2008, $20.8 million was spent on continued development of cavern storage, the condensate offloading and terminalling facility, and expansion to the recently completed truck loading facilities. In addition, $7.7 million was added to capitalized line-fill, $8.2 million was spent on sustaining capital requirements and $1.1 million was spent primarily on development of systems to improve information flow within the business unit.

Discontinued operations (USOGP)

In February 2008, the Trust announced a strategic process respecting the decision to sell the operations that comprise the United States oil and natural gas production (USOGP) business. This business was comprised of approximately 22 percent ownership of BreitBurn Energy Partners, L.P., a publicly-traded U.S. Master Limited Partnership ("the MLP"). This MLP ownership also included units held by the General Partner of which Provident owned approximately 96 percent. In addition, Provident owned approximately 96 percent of privately held BreitBurn Energy Company L.P. ("BreitBurn") which operates assets in California.

Effective in the first quarter of 2008, the USOGP business was accounted for as discontinued operations. Discontinued operations (USOGP) includes the consolidated results of 100 percent of the MLP and BreitBurn. Non-controlling interests are comprised mainly of the public ownership in the MLP, and to a lesser extent the ownership interests of the managers in the MLP and BreitBurn, as well as third party investment in USOGP's land development project, which commenced in 2006.

In June 2008, the Trust sold a portion of the USOGP business, consisting of its 22 percent interest in BreitBurn Energy Partners, L.P. (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 has recorded a gain on sale of $187.9 million and $127.7 million in current tax expense related to this transaction. Also recorded was a realized foreign exchange loss of $30.3 million, representing the recognition of the related portion of the foreign exchange loss in accumulated other comprehensive income, which was generated since inception in 2006. These amounts are recorded as part of net income from discontinued operations for the year ended December 31, 2008.

In August 2008, the Trust sold the remaining portion of the USOGP business, comprised of an approximate 96 percent interest in BreitBurn Energy Company 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 has recorded a gain on sale of $75.7 million and $66.9 million in current tax expense related to this transaction. Also recorded was a realized foreign exchange loss of $26.8 million, representing the recognition of the related portion of the foreign exchange loss in accumulated other comprehensive income, which was generated since acquisition in 2004. These amounts are recorded as part of net income from discontinued operations for the year ended December 31, 2008.

Quicksilver Resources Inc. ("Quicksilver") filed a lawsuit on October 31, 2008 against the MLP, certain of its directors (including three Provident nominees), and Provident. 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. The litigation is in its very early stages, and it is not possible at this time to assess the potential exposure of Provident in the event of an adverse verdict. Provident believes the claims made against it in the lawsuit are without merit and will vigorously defend itself and its named director nominees against these claims.

Foreign ownership

Based on information received from our transfer agent and financial intermediaries in January 2009, 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") 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 13 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. Utilization of the full cost method of accounting requires the use of management estimates and assumptions for amounts recorded for depletion and depreciation of property, plant and equipment as well as for the ceiling test.

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

Proved reserves are an estimate, under existing reserve evaluation polices, of volumes that can reasonably be expected to be economically recoverable under existing technology and economic conditions. Changes in underlying assumptions or economic conditions could have a material impact on Provident's financial results. To mitigate these risks, management utilizes McDaniel & Associates Consultants Ltd. 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.

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

Change in accounting policies

(i) Inventory

In the first quarter of 2008, the Trust adopted the new accounting standard, CICA Handbook Section 3031 - Inventories, which replaced the previous standard for inventories, Section 3030. The main features of the new Section are as follows:

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

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

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

Adoption of the new Section has not had a material impact on the consolidated financial statements.

(ii) Capital disclosures

In the first quarter of 2008, the Trust adopted CICA Handbook Section 1535 "Capital Disclosures" which addresses the requirements for an entity to disclose qualitative information about its objectives, policies and processes for managing capital. This section also establishes the requirement for an entity to disclose quantitative data about what it regards as capital as well as disclose whether it has complied with any externally imposed capital requirements and, if not, the consequences of such non-compliance. The new disclosure is included in note 14.

(iii) Financial instruments - disclosures

In the first quarter of 2008, the Trust adopted CICA Handbook Section 3862 "Financial Instruments- Disclosures" and Section 3863 "Financial Instruments-Presentation". Section 3862 requires entities to provide disclosures in their financial statements that enable users to evaluate the significance of financial instruments to the entity's financial position and performance. It also requires that entities disclose the nature and extent of risks arising from financial instruments and how the entity manages those risks. Section 3863 establishes presentation guidelines for financial instruments and non-financial derivatives and addresses the classification of financial instruments, from the perspective of the issuer, between liabilities and equity, the classification of related interest, dividends, losses and gains, and circumstances in which financial assets and financial liabilities are offset. The new disclosure is included in note 13.

(iv) 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.

Provident has commenced the process to transition from current Canadian GAAP to IFRS. It has established a project plan and a project team. 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 commenced and will continue throughout the subsequent phases. Regular reporting is provided to Provident's senior management and to the Audit Committee of the Board of Directors.

Provident is currently engaged in the detailed assessment and design phase of the project. The detailed assessment and design phase involves established work teams to complete 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 and an analysis of financial systems has commenced.

During the implementation phase, Provident will execute the required changes to business processes, financial systems, accounting policies, disclosure controls and internal controls over financial reporting. At this time, the impact on the consolidated financial statements is not reasonably determinable.

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

Business risks

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

- capital markets, 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 new tax on trust distributions.

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

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

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

- 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;

- marketability of oil and natural gas;

- the ability to attract and retain employees; and

- environmental, health and safety risks.

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

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

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

- exposure to commodity price fluctuations;

- the ability to attract and retain employees;

- regulatory intervention in determining processing fees and tariffs; and

- reliance on significant customers.

Provident strives to minimize these business risks by:

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

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

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

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

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

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

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

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

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

- maintaining an adequate level of property, casualty, comprehensive and directors' and officers' insurance coverage.

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, 2008 on both the Toronto Stock Exchange and the New York Stock Exchange:



Q1 Q2 Q3 Q4
----------------------------------------------------------------------------
TSE - PVE.UN (Cdn$)
High $ 11.37 $ 12.25 $ 11.66 $ 9.55
Low $ 8.80 $ 10.76 $ 8.71 $ 4.68
Close $ 10.95 $ 11.74 $ 9.50 $ 5.35
Volume (000s) 34,702 28,161 26,269 31,780
----------------------------------------------------------------------------
NYSE - PVX (US$)
High $ 11.28 $ 12.40 $ 11.50 $ 9.00
Low $ 8.50 $ 10.50 $ 8.50 $ 3.64
Close $ 10.60 $ 11.43 $ 8.98 $ 4.36
Volume (000s) 74,533 77,141 76,617 147,340
----------------------------------------------------------------------------


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. 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 of exploration;

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

- currency, exchange and interest rates; and

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

Readers are cautioned that the foregoing list is not exhaustive of all factors and assumptions which have been used. 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) 2008 2007 2006
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Revenue from continuing operations (net
of royalties and financial
derivative instruments) $ 3,239,163 $ 2,038,515 $ 2,023,178
Net income 157,392 30,434 140,920
Net income per unit - basic and diluted 0.62 0.13 0.72
Total assets 3,074,069 5,758,792 3,370,919
Long-term financial liabilities from
continuing operations (1) 867,232 1,382,921 1,065,932
Declared distributions per unit. $ 1.38 $ 1.44 $ 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) 2008
----------------------------------------------------------------------------
First Second Third Fourth Annual
Quarter Quarter Quarter Quarter Total
----------------------------------------------------------------------------
Financial -
consolidated
Revenue
(continuing
operations) $702,215 $ 420,220 $ 1,097,408 $ 1,019,320 $ 3,239,163
Funds flow from
operations $180,230 $ 241,487 $ 151,661 $ 81,779 $ 655,157
Net income
(loss) $ 33,616 $ (184,081) $ 351,105 $ (43,248) $ 157,392
Net income
(loss)
per unit
- basic $ 0.13 $ (0.72) $ 1.37 $ (0.17) $ 0.62
Net income
(loss)
per unit
- diluted $ 0.13 $ (0.72) $ 1.29 $ (0.17) $ 0.62
Unitholder
distributions $ 91,117 $ 91,662 $ 92,188 $ 77,324 $ 352,291
Distributions
per unit $ 0.36 $ 0.36 $ 0.36 $ 0.30 $ 1.38
----------------------------------------------------------------------------
----------------------------------------------------------------------------

Oil and gas
production
(continuing
operations)
Cash revenue $122,815 $ 164,442 $ 158,400 $ 101,437 $ 547,094
Earnings before
interest, DD&A,
taxes and other
non-cash items $ 75,348 $ 117,132 $ 111,256 $ 49,757 $ 353,493
Funds flow from
operations $ 71,142 $ 112,869 $ 107,442 $ 47,187 $ 338,640
Net income
(loss) $ 9,591 $ 28,935 $ 76,881 $ (421,457) $ (306,050)
----------------------------------------------------------------------------
----------------------------------------------------------------------------

Provident
Midstream
Cash revenue $641,673 $ 662,315 $ 652,753 $ 513,860 $ 2,470,601
Earnings before
interest, DD&A,
taxes and other
non-cash items $ 75,987 $ 61,769 $ 37,339 $ 37,666 $ 212,761
Funds flow from
operations $ 59,252 $ 52,601 $ 32,537 $ 34,592 $ 178,982
Net income
(loss) $ 15,516 $ (290,230) $ 232,966 $ 359,166 $ 317,418
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Operating
Oil and gas
production
(continuing
operations)
Light/medium oil
(bpd) 10,535 10,179 10,109 9,885 10,176
Heavy oil (bpd) 1,752 2,315 2,696 2,422 2,297
Natural gas
liquids
(bpd) 1,307 1,178 1,195 1,134 1,203
Natural gas
(mcfd) 83,970 86,130 85,628 80,450 84,039
Oil equivalent
(boed) 27,589 28,027 28,271 26,849 27,683
----------------------------------------------------------------------------
----------------------------------------------------------------------------

Average selling
price net of
transportation
expense
(continuing
operations)
(Cdn$)
Crude oil per
bbl (before
realized
financial
derivative
instruments) $ 75.06 $ 105.13 $ 102.66 $ 47.33 $ 82.79
Crude oil per
bbl (including
realized
financial
derivative
instruments) $ 71.54 $ 98.68 $ 97.61 $ 52.71 $ 80.36
Natural gas
liquids
per barrel $ 72.85 $ 94.59 $ 91.72 $ 47.64 $ 76.88
Natural gas per
mcf (before
realized
financial
derivative
instruments) $ 7.61 $ 9.98 $ 8.60 $ 6.63 $ 8.23
Natural gas
per mcf
(including
realized
financial
derivative
instruments) $ 7.74 $ 9.73 $ 8.45 $ 6.92 $ 8.23
----------------------------------------------------------------------------
----------------------------------------------------------------------------

Provident
Midstream
Provident
Midstream
NGL sales
volumes (bpd) 136,320 110,826 111,313 120,222 119,649
----------------------------------------------------------------------------
----------------------------------------------------------------------------


Quarterly table

----------------------------------------------------------------------------
Segmented information by quarter
($ 000s except for per unit
and operating amounts) 2007
----------------------------------------------------------------------------
First Second Third Fourth Annual
Quarter Quarter Quarter Quarter Total
----------------------------------------------------------------------------
Financial -
consolidated
Revenue
(continuing
operations) $558,807 $ 463,995 $ 494,065 $ 521,648 $ 2,038,515
Funds flow from
operations $ 87,040 $ 98,503 $ 105,149 $ 177,563 $ 468,255
Net income
(loss) $ 43,093 $ (46,199) $ (35,005) $ 68,545 $ 30,434
Net income
(loss)
per unit -
basic and
diluted $ 0.20 $ (0.21) $ (0.14) $ 0.28 $ 0.13
Unitholder
distributions $ 76,271 $ 80,236 $ 87,782 $ 89,063 $ 333,352
Distributions per
unit $ 0.36 $ 0.36 $ 0.36 $ 0.36 $ 1.44
----------------------------------------------------------------------------

Oil and gas
production
(continuing
operations)
Cash revenue $ 84,668 $ 90,028 $ 92,419 $ 101,746 $ 368,861
Earnings before
interest, DD&A,
taxes and other
non-cash items $ 49,756 $ 55,457 $ 53,530 $ 63,009 $ 221,752
Funds flow from
operations $ 46,410 $ 52,032 $ 47,143 $ 58,667 $ 204,252
Net (loss) income $ (4,510) $ 50,429 $ (17,807) $ 16,953 $ 45,065
----------------------------------------------------------------------------

Provident
Midstream
Cash revenue $453,272 $ 397,713 $ 433,950 $ 598,963 $ 1,883,898
Earnings before
interest, DD&A,
taxes and other
non-cash items $ 52,853 $ 35,974 $ 47,425 $ 89,423 $ 225,675
Funds flow from
operations $ 39,404 $ 29,569 $ 32,350 $ 77,109 $ 178,432
Net income (loss) $ 51,838 $(142,191) $ (8,630) $ (62,037) $ (161,020)
----------------------------------------------------------------------------

Operating
Oil and gas
production
(continuing
operations)
Light/medium oil
(bpd) 6,428 6,692 8,858 9,483 7,876
Heavy oil (bpd) 1,669 1,918 2,324 1,769 1,921
Natural gas
liquids (bpd) 1,422 1,311 1,255 1,277 1,316
Natural gas (mcfd) 88,928 94,437 93,511 92,584 92,378
Oil equivalent
(boed) 24,340 25,660 28,022 27,960 26,509
----------------------------------------------------------------------------

Average selling
price net of
transportation
expense
(continuing
operations)(Cdn$)
Crude oil
per bbl
(before realized
financial
derivative
instruments) $ 51.23 $ 53.75 $ 57.88 $ 61.75 $ 56.74
Crude oil
per bbl
(including
realized
financial
derivative
instruments) $ 51.25 $ 52.77 $ 55.47 $ 57.23 $ 54.53
Natural gas
liquids
per barrel $ 49.02 $ 52.79 $ 55.47 $ 63.63 $ 55.07
Natural gas per
mcf (before
realized
financial
derivative
instruments) $ 7.48 $ 7.27 $ 4.94 $ 6.08 $ 6.42
Natural gas per
mcf (including
realized
financial
derivative
instruments) $ 7.37 $ 7.20 $ 5.63 $ 6.68 $ 6.71
----------------------------------------------------------------------------

Provident
Midstream
Provident
Midstream
NGL sales
volumes (bpd) 125,033 109,713 112,386 135,981 120,785
----------------------------------------------------------------------------


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, 2008, 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, 2008, has been audited by PricewaterhouseCoopers LLP, independent auditors, as stated in their report which appears herein.

"signed"

Thomas W. Buchanan

Chief Executive Officer

"signed"

Mark N. Walker

Chief Financial Officer

Calgary, Alberta

March 11, 2009

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"

Thomas W. Buchanan

Chief Executive Officer

"signed"

Mark N. Walker

Chief Financial Officer

Calgary, Alberta

March 11, 2009

Independent Auditors' Report

To the Unitholders of Provident Energy Trust

We have completed integrated audits of Provident Energy Trust's (the "Trust") 2008 and 2007 consolidated financial statements and of its internal control over financial reporting as at December 31, 2008. 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, 2008 and December 31, 2007, 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, 2008 and December 31, 2007 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, 2008, 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.

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, 2008 based on criteria established in Internal Control - Integrated Framework issued by the COSO.

PricewaterhouseCoopers LLP

Chartered Accountants

March 11, 2009



PROVIDENT ENERGY TRUST
CONSOLIDATED BALANCE SHEETS
Canadian dollars (000s)

As at As at
December 31, December 31,
2008 2007
-------------------------------
Assets
Current assets
Cash and cash equivalents $ 4,629 $ -
Accounts receivable 244,485 338,105
Petroleum product inventory 46,160 84,638
Prepaid expenses and other current assets 7,886 8,313
Financial derivative instruments (note 13) 16,708 1,329
Assets held for sale - USOGP (note 15) - 93,578
----------------------------------------------------------------------------
319,868 525,963

Investments and other long term assets 14,218 5,862
Long-term financial derivative instruments (note 13) 735 -
Property, plant and equipment (note 5) 2,480,503 2,510,271
Intangible assets (note 6) 158,336 171,793
Goodwill (note 7) 100,409 517,299
Assets held for sale - USOGP (note 15) - 2,027,604
----------------------------------------------------------------------------
$ 3,074,069 $ 5,758,792
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Liabilities
Current liabilities
Accounts payable and accrued liabilities $ 244,031 $ 347,224
Cash distributions payable 20,088 25,100
Current portion of convertible debentures (note 8) 24,871 19,198
Financial derivative instruments (note 13) 13,693 130,276
Liabilities held for sale - USOGP (note 15) - 114,681
----------------------------------------------------------------------------
302,683 636,479

Long-term debt - revolving term credit facility
(note 8) 504,685 923,996
Long-term debt - convertible debentures
(note 8) 236,123 256,440
Asset retirement obligation (note 9) 59,432 43,886
Long-term financial derivative instruments (note 13) 58,420 146,199
Other long-term liabilities (note 11) 8,572 12,400
Future income taxes (note 12) 267,807 302,089
Liabilities held for sale - USOGP (note 15) - 628,502
Non-controlling interests (note 15)
Discontinued operations (USOGP) - 1,100,136

Unitholders' equity
Unitholders' contributions (note 10) 2,806,071 2,750,374
Convertible debentures equity component 17,198 18,213
Contributed surplus (note 11) 1,695 801
Accumulated other comprehensive loss (2,183) (69,188)
Accumulated income 426,034 268,642
Accumulated cash distributions (1,612,468) (1,260,177)
----------------------------------------------------------------------------
1,636,347 1,708,665
----------------------------------------------------------------------------
$ 3,074,069 $ 5,758,792
----------------------------------------------------------------------------
----------------------------------------------------------------------------

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

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


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

Year ended
December 31,
----------------------------
2008 2007
----------------------------
Revenue
Revenue $ 3,147,714 $ 2,325,505
Realized loss on financial derivative
instruments (130,019) (72,746)
Unrealized gain (loss) on financial derivative
instruments 221,468 (214,244)
----------------------------------------------------------------------------
3,239,163 2,038,515

Expenses
Cost of goods sold 2,206,427 1,594,639
Production, operating and maintenance 153,111 126,481
Transportation 37,120 25,018
Depletion, depreciation and accretion 343,315 301,111
Goodwill impairment (note 7) 416,890 -
General and administrative (note 11) 66,913 62,353
Interest on bank debt 36,088 44,221
Interest and accretion on convertible debentures 19,944 14,687
Foreign exchange (gain) loss and other (20,828) 4,202
----------------------------------------------------------------------------
3,258,980 2,172,712
----------------------------------------------------------------------------

Loss from continuing operations before taxes (19,817) (134,197)
----------------------------------------------------------------------------

Capital tax expense 3,109 3,762
Current and withholding tax (recovery) expense (4,529) 6,352
Future income tax recovery (note 12) (29,765) (28,356)
----------------------------------------------------------------------------
(31,185) (18,242)
----------------------------------------------------------------------------
Net income (loss) from continuing operations 11,368 (115,955)
Net income from discontinued operations (note 15) 146,024 146,389
----------------------------------------------------------------------------
Net income 157,392 30,434
----------------------------------------------------------------------------
Accumulated income, beginning of year $ 268,642 $ 238,208
----------------------------------------------------------------------------
Accumulated income, end of year $ 426,034 $ 268,642
----------------------------------------------------------------------------
Net income (loss) from continuing operations
per unit
- basic and diluted $ 0.04 $ (0.50)
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Net income per unit
- basic and diluted $ 0.62 $ 0.13
----------------------------------------------------------------------------

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


PROVIDENT ENERGY TRUST
CONSOLIDATED STATEMENT OF CASH FLOWS
Canadian dollars (000s)
Year ended
December 31,
----------------------------
2008 2007
----------------------------

Cash provided by operating activities
Net income (loss) for the year from continuing
operations $ 11,368 $ (115,955)
Add (deduct) non-cash items:
Depletion, depreciation and accretion 343,315 301,111
Goodwill impairment (note 7) 416,890 -
Non-cash interest expense and other 5,291 2,797
Non-cash unit based compensation (recovery)
expense (note 11) (4,117) 8,064
Unrealized (gain) loss on financial derivative
instruments (221,468) 214,244
Unrealized foreign exchange (gain) loss and
other (3,892) 779
Future income tax recovery (note 12) (29,765) (28,356)
----------------------------------------------------------------------------
Funds flow from continuing operations 517,622 382,684
Funds flow from discontinued operations 137,535 85,571
----------------------------------------------------------------------------
Funds flow from operations 655,157 468,255
----------------------------------------------------------------------------
Site restoration expenditures (6,381) (4,062)
Change in non-cash operating working capital
from continuing operations 52,684 4,807
Change in non-cash operating working capital
from discontinued operations (27,034) (4,545)
----------------------------------------------------------------------------
674,426 464,455
----------------------------------------------------------------------------

Cash (used for) provided by financing activities
(Decrease) increase in long-term debt (440,244) 169,122
Declared distributions to unitholders (352,291) (333,352)
Issue of trust units, net of issue costs 55,510 412,909
Change in non-cash financing working capital (5,028) 2,856
Financing activities from discontinued operations (47,511) 1,011,670
----------------------------------------------------------------------------
(789,564) 1,263,205
----------------------------------------------------------------------------

Cash provided by (used for) investing activities
Capital expenditures (246,947) (178,113)
Capitol Energy acquisition (note 4) - (467,495)
Triwest Energy acquisition (note 4) - (2,300)
Oil and gas property acquisitions (24,181) (13,050)
Increase in investments (792) (5,450)
Proceeds on sale of assets - 7,624
Proceeds on sale of discontinued operations, net
of tax (note 15) 457,906 -
Change in non-cash investing working capital (3,229) 14,920
Investing activities from discontinued
operations (69,810) (1,087,278)
----------------------------------------------------------------------------
112,947 (1,731,142)
----------------------------------------------------------------------------

(Decrease) increase in cash and cash equivalents (2,191) (3,482)
Cash and cash equivalents, beginning of year 6,820 10,302
----------------------------------------------------------------------------
Cash and cash equivalents, end of year $ 4,629 $ 6,820
Cash and cash equivalents, end of year from
discontinued operations $ - $ 6,820
----------------------------------------------------------------------------
Cash and cash equivalents, end of year from
continuing operations $ 4,629 $ -
----------------------------------------------------------------------------
----------------------------------------------------------------------------

Supplemental disclosure of cash flow information
Cash interest paid including debenture interest $ 63,490 $ 69,600
Cash taxes paid (note 15) $ 210,132 $ 13,741
----------------------------------------------------------------------------

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


PROVIDENT ENERGY TRUST
CONSOLIDATED STATEMENT OF COMPREHENSIVE
AND ACCUMULATED OTHER COMPREHENSIVE INCOME
Canadian Dollars (000s)

Year ended
December 31,
-----------------------------
2008 2007
-----------------------------

Net income $ 157,392 $ 30,434
----------------------------------------------------------------------------

Other comprehensive income (loss), net of taxes
Foreign currency translation adjustments 10,315 (25,083)
Reclassification adjustment for foreign
currency losses included in net income 57,062 -
Unrealized loss on available-for-sale
investments (net of taxes) (372) (1,811)
----------------------------------------------------------------------------
67,005 (26,894)
----------------------------------------------------------------------------

Comprehensive income $ 224,397 $ 3,540
----------------------------------------------------------------------------
----------------------------------------------------------------------------

Accumulated other comprehensive loss, beginning
of year (69,188) (42,294)
Other comprehensive income (loss) 67,005 (26,894)
----------------------------------------------------------------------------
Accumulated other comprehensive loss, end of
year $ (2,183) $ (69,188)
----------------------------------------------------------------------------
----------------------------------------------------------------------------

Accumulated income, end of year 426,034 268,642
Accumulated cash distributions, end of year (1,612,468) (1,260,177)
----------------------------------------------------------------------------
Retained earnings (deficit), end of year (1,186,434) (991,535)
Accumulated other comprehensive loss, end of year (2,183) (69,188)
----------------------------------------------------------------------------
Total retained earnings (deficit) and
accumulated other comprehensive loss, end of
year $ (1,188,617) $ (1,060,723)
----------------------------------------------------------------------------

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


Notes to the Consolidated
Financial Statements
(Tabular amounts in Cdn $ 000's, except unit and per unit amounts)
December 31, 2008


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 Provident Energy Ltd. and other directly and indirectly owned subsidiaries of the Trust. Cash flow is paid to the Trust by way of royalty payments, interest payments and principal debt repayments. The cash payments received by the Trust are subsequently distributed to the unitholders monthly.

2. Significant accounting policies

i) Principles of consolidation and investments

The consolidated financial statements include the accounts of the Trust, 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. In particular, the comparative figures have been reclassified to reflect discontinued operations presentation for the United States oil and natural gas production (USOGP) business (see note 15).

ii) Financial instruments

All financial instruments, including derivatives, are recognized on the Trust's Consolidated Balance Sheet. Derivatives are measured at fair value with unrealized gains and losses reported in net income. Investments, other than investments accounted for by the equity method, are measured at fair value, with reference to published price quotations, and unrealized gains and losses are reported in AOCI. The Trust's other financial instruments (accounts receivable, accounts payable and 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 (see note 3).

iii) Cash and cash equivalents

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

iv) Property, plant & equipment and intangible assets

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

a) Depletion, depreciation and accretion

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

Midstream facilities, including natural gas liquids storage facilities and natural gas liquids processing and extraction facilities are carried at cost and depreciated on a straight-line basis over the estimated service lives of the assets, which range from 30 to 40 years. Intangible assets are amortized over the estimated useful lives of the assets, which range from 12 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 cost centre to the sum of the undiscounted proved reserve cash flows expected from the cost centre by country using future price estimates. If the carrying value is not recoverable, the cost centre is written down to its fair value. Fair value is determined by the future cash flows from the proved plus probable reserves discounted at the Trust's risk free interest rate. Any excess carrying value of the assets on the balance sheet above fair value would be recorded in depletion, depreciation and accretion expense as a permanent impairment.

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

v) Joint venture

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

vi) Inventory

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

vii) Goodwill

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

viii) Asset retirement obligation

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

ix) Unit based compensation

The Trust uses the fair value method of valuing compensation expense associated with the Trust's unit option plan. Provident has applied this method to options issued after January 1, 2003, the effective date for implementing stock based compensation. Under the fair value method the amount to be recognized as expense is determined at the time the options are issued and is recognized in earnings over the vesting period of the options with a corresponding increase in contributed surplus.

The Trust has established other unit based compensation plans whereby notional units are granted to employees. The fair value of these notional units is estimated and recorded as 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.

xii) Revenue recognition

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

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

(i) Inventory

In the first quarter of 2008, the Trust adopted the new accounting standard, CICA Handbook Section 3031 - Inventories, which replaced the previous standard for inventories, Section 3030. The main features of the new Section are as follows:

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

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

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

Adoption of the new Section has not had a material impact on the consolidated financial statements.

(ii) Capital disclosures

In the first quarter of 2008, the Trust adopted CICA Handbook Section 1535 "Capital Disclosures" which addresses the requirements for an entity to disclose qualitative information about its objectives, policies and processes for managing capital. This section also establishes the requirement for an entity to disclose quantitative data about what it regards as capital as well as disclose whether it has complied with any externally imposed capital requirements and, if not, the consequences of such non-compliance. The new disclosure is included in note 14.

(iii) Financial instruments - disclosures

In the first quarter of 2008, the Trust adopted CICA Handbook Section 3862 "Financial Instruments-Disclosures" and Section 3863 "Financial Instruments-Presentation". Section 3862 requires entities to provide disclosures in their financial statements that enable users to evaluate the significance of financial instruments to the entity's financial position and performance. It also requires that entities disclose the nature and extent of risks arising from financial instruments and how the entity manages those risks. Section 3863 establishes presentation guidelines for financial instruments and non-financial derivatives and addresses the classification of financial instruments, from the perspective of the issuer, between liabilities and equity, the classification of related interest, dividends, losses and gains, and circumstances in which financial assets and financial liabilities are offset. The new disclosure is included in note 13.

B. Recent accounting pronouncements

i) Goodwill and intangible assets

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

ii) 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. At this time, the impact on the Trust's consolidated financial statements is not reasonably determinable.

4. Acquisitions

i) Acquisition of Triwest

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



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


ii) Acquisition of Capitol

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



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


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



5. Property, plant and equipment

Accumulated
depletion and Net Book
Year ended December 31, 2008 Cost depreciation value
---------------------------------------------------------------------------
Oil and natural gas properties $ 3,125,360 $ 1,411,997 $ 1,713,363
Midstream assets 827,172 87,674 739,498
Office equipment 44,678 17,036 27,642
---------------------------------------------------------------------------
Total $ 3,997,210 $ 1,516,707 $ 2,480,503
---------------------------------------------------------------------------
---------------------------------------------------------------------------


Accumulated
depletion and Net Book
Year ended December 31, 2007 Cost depreciation value
---------------------------------------------------------------------------
Oil and natural gas properties $ 2,870,191 $ 1,116,281 $ 1,753,910
Midstream assets 790,434 63,763 726,671
Office equipment 40,936 11,246 29,690
---------------------------------------------------------------------------
Total $ 3,701,561 $ 1,191,290 $ 2,510,271
---------------------------------------------------------------------------
---------------------------------------------------------------------------


Costs associated with unproved properties and major development projects excluded from costs subject to depletion as at December 31, 2008 totaled $93.1 million (December 31, 2007 - $137.7 million). Midstream assets include $41.8 million (2007 - $35.9 million) for products required for line-fill and cavern bottoms.

An impairment test calculation was performed on property, plant and equipment at December 31, 2008 in which the estimated undiscounted future net cash flows based on estimated future prices associated with the proved reserves exceeded the carrying amount of oil and gas property, plant and equipment for each cost centre.

The following table outlines prices used in the impairment test at December 31, 2008:



Oil Gas NGL
Year $/bbl $/mcf $/bbl
---------------------------------------------------------------------------
2009 $ 56.95 $ 7.12 $ 51.51
2010 $ 64.13 $ 7.37 $ 59.63
2011 $ 70.46 $ 7.64 $ 66.15
2012 $ 76.25 $ 7.92 $ 71.46
2013 $ 81.08 $ 8.21 $ 76.75
Thereafter (1) 2% 2% 2%
---------------------------------------------------------------------------
---------------------------------------------------------------------------
(1) Percentage change represents the increase in each year after 2013 to
the end of the reserve life.



6. Intangible assets

Accumulated Net Book
December 31, 2008 Cost amortization value
---------------------------------------------------------------------------
Midstream contracts and
customer relationships $ 183,100 37,255 $ 145,845
Other intangible assets
- Midstream 16,308 3,817 12,491
---------------------------------------------------------------------------
Total $ 199,408 $ 41,072 $ 158,336
---------------------------------------------------------------------------
---------------------------------------------------------------------------


Accumulated Net Book
December 31, 2007 Cost amortization value
---------------------------------------------------------------------------
Midstream contracts and
customer relationships $ 183,100 $ 25,049 $ 158,051
Other intangible assets
- Midstream 16,308 2,566 13,742
---------------------------------------------------------------------------
Total $ 199,408 $ 27,615 $ 171,793
---------------------------------------------------------------------------
---------------------------------------------------------------------------


7. 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, 2007 Goodwill was comprised of $416.9 million related to acquisitions in the Canadian oil and gas business and $100.4 million resulted from the Midstream NGL Acquisition in 2005.

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 2008, 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 2008 and determined that the fair value of the Canadian oil and gas production unit was lower than the respective carrying value, primarily due to increasing economic uncertainty in the global market and the resulting higher cost of capital assumptions in the valuation methodologies. Consequently, a goodwill impairment, amounting to $416.9 million was recorded. The impairment test indicated that the fair value of the Midstream reporting unit was in excess of the respective carrying value, therefore no write down of midstream-related goodwill was required. At December 31, 2008 the goodwill balance of $100.4 million is related entirely to the Provident Midstream reporting unit.

8. Long-term debt



December 31, December 31,
2008 2007
---------------------------------------------------------------------------
Revolving term credit facility $ 504,685 $ 923,996
---------------------------------------------------------------------------
Convertible debentures 260,994 275,638
Current portion of convertible debentures (24,871) (19,198)
---------------------------------------------------------------------------
236,123 256,440
---------------------------------------------------------------------------
Total $ 740,808 $ 1,180,436
---------------------------------------------------------------------------
---------------------------------------------------------------------------


i) Revolving term credit facility

Provident has a $1,125 million term credit facility (2007 - $1,125 million) with a syndicate of banks secured by midstream assets and by its Canadian oil and gas properties. Provident may draw on the credit facility by way of Canadian prime rate loans, U.S. base rate loans, banker's acceptances, letters of credit or LIBOR loans. At December 31, 2008, $504.9 million was drawn on this facility. Included in the carrying value at December 31, 2008 were financing costs of $0.2 million.

The terms of the credit facility have a revolving three year period expiring on May 30, 2011.

At December 31, 2008 the effective interest rate of the outstanding credit facility was 3.3 percent (2007 - 5.6 percent). At December 31, 2008 Provident had $35.2 million in letters of credit outstanding (2007 - $31.6 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, 2008, $0.1 million of the face value of debentures were converted to trust units at the election of debenture holders (2007 - $6.1 million). Upon maturity in 2008, the Trust repaid $19.9 million to the holders of its 8.75 percent convertible debentures, and the balance of the equity component of the 8.75 percent convertible debentures, amounting to $1.0 million, was transferred to contributed surplus. Included in the carrying value at December 31, 2008 were financing costs of $4.7 million. The fair value of the convertible debentures at December 31, 2008 approximates the face value of the instruments. The following table details each outstanding convertible debenture.



As at As at
Convertible December 31, December 31,
Debentures 2008 2007
---------------------------------------------------------------------------
($000s except Conversion
conversion Carrying Face Carrying Face Maturity Price per
pricing) Value (1) Value Value (1) Value Date unit (2)
---------------------------------------------------------------------------
6.5% Convertible April 30,
Debentures $ 143,212 $ 149,980 140,515 $ 149,980 2011 14.75
6.5% Convertible Aug. 31,
Debentures 92,911 98,999 91,460 99,024 2012 13.75
8.0% Convertible July 31,
Debentures 24,871 25,109 24,465 25,109 2009 12.00
8.75% Convertible Dec. 31,
Debentures - - 19,198 19,931 2008 11.05
---------------------------------------------------------------------------
$ 260,994 $ 274,088 $ 275,638 $ 294,044
---------------------------------------------------------------------------
---------------------------------------------------------------------------
(1) Excluding equity component of convertible debentures
(2) The debentures may be converted into trust units at the option of the
holder of the debenture at the conversion price per unit


9. 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 seven percent and an inflation rate of two percent has been estimated for future years.

The total undiscounted amount of future cash flows required to settle asset retirement obligations related to oil and gas operations is estimated to be $348.5 million (2007 - $310.7 million). Payments to settle oil and gas asset retirement obligations occur over the operating lives of the assets estimated to be over the next 51 years.

The total undiscounted amount of future cash flows required to settle the midstream asset retirement obligations is estimated to be $166.1 million (2007 - $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 25 to 41 years.



Year ended December 31,
---------------------------------------------------------------------------
($000s) 2008 2007
---------------------------------------------------------------------------
Carrying amount, beginning of year $ 43,886 $ 33,246
Acquisitions - 2,504
Change in estimate 15,759 7,127
Increase in liabilities incurred during the year 1,729 2,221
Settlement of liabilities during the year (6,381) (4,062)
Decrease in liabilities due to disposition - (654)
Accretion of liability 4,439 3,504
---------------------------------------------------------------------------
Carrying amount, end of year $ 59,432 $ 43,886
---------------------------------------------------------------------------
---------------------------------------------------------------------------


Provident funds a cash reserve for future site reclamation by paying $0.30 per barrel of oil equivalent produced on a 6:1 basis into a segregated cash account. Actual expenditures are then funded from the cash in this account. The cash account has been depleted since 2006 as actual expenditures have exceeded contributions to the reserve.

10. Unitholders' contributions

The Trust has authorized capital of an unlimited number of common voting trust units.

Trust units are redeemable at any time on demand by the holders thereof. Upon receipt of a redemption request by the Trust, the holder is entitled to receive a price per trust unit (the "Market Redemption Price") equal to the lesser of: (i) 90 percent of the simple average of the closing price of the trust units on the principal market on which the trust units are quoted for trading during the 10 trading day period commencing immediately after the date on which the trust units are surrendered for redemption; and (ii) the closing market price on the principal market on which the trust units are quoted for trading on the date that the trust units are surrendered for redemption.

The aggregate Market Redemption Price payable by the Trust in respect of any trust units surrendered for redemption during any calendar month shall be satisfied by way of a cash payment on the last day of the following month. Total cash payments for redemption are limited to an annual maximum of $250,000. Any excess over the maximum may be satisfied by distributing notes having an aggregate principal amount equal to the aggregate Market Redemption Price of the trust units tendered for redemption.

i) 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.

ii) 2007 activity

In 2007, the Trust issued 29,313,727 trust units at a price of $12.75 per unit for total proceeds of $373.8 million ($354.6 million net of issue costs). Proceeds from the issue were used to fund the Capitol acquisition, which closed on June 19, 2007.

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

In 2007, the Trust issued 5.8 million units related to Provident's DRIP program, conversion of convertible debentures to units and units issued pursuant to Provident's Unit Option Plan. The increase in unitholders' contributions associated with these activities was $65.2 million.



Year ended December 31,
---------------------------------------------------------------------------
2008 2007
---------------------------------------------------------------------------
Number of Amount Number of Amount
Trust Units Units (000s) units (000s)
---------------------------------------------------------------------------
Balance at beginning
of year 252,634,773 $ 2,750,374 211,228,407 $ 2,254,048
Issued for cash - - 29,313,727 373,750
Issued to acquire
Triwest Energy Inc. - - 6,251,149 76,577
Issued pursuant to
unit option plan 191,448 1,790 825,349 8,426
Issued pursuant
to the distribution
reinvestment plan 5,600,810 50,667 3,941,864 45,338
To be issued pursuant
to the distribution
reinvestment plan 655,142 3,171 525,822 5,153
Debenture conversions 5,616 69 548,455 6,270
Unit issue costs - - - (19,188)
---------------------------------------------------------------------------
Balance at end of year 259,087,789 $ 2,806,071 252,634,773 $ 2,750,374
---------------------------------------------------------------------------
---------------------------------------------------------------------------


The basic per trust unit amounts for 2008 were calculated based on the weighted average number of units outstanding of 255,177,346 (2007 - 229,939,158). The diluted per trust unit amounts for 2008 are calculated including no additional trust units (2007 - nil) for the dilutive effect of the unit option plan and the convertible debentures.

11. Unit based compensation

i) Restricted/Performance units

Certain employees of the Trust are granted restricted trust units (RTUs) and/or performance trust units (PTUs), both of which entitle the employee to receive cash compensation in relation to the value of a specific number of underlying notional trust units. The grants are based on criteria designed to recognize the long term value of the employee to the organization. RTUs vest evenly over a period of three years commencing at the grant date. Payments are made on the anniversary dates of the RTU to the employees entitled to receive them on the basis of a cash payment equal to the value of the underlying notional units. PTUs vest three years from the date of grant and can be increased to a maximum of double the PTUs granted or a minimum of nil PTUs depending on the Trust's performance vis-a-vis other trusts' performance based on certain benchmarks.

As of December 31, 2008 there were 1,139,835 RTUs and 3,400,330 PTUs outstanding (2007 - 849,672 RTUs and 2,478,037 PTUs). The fair value estimate associated with the RTUs and PTUs is expensed in the statement of operations over the vesting period. At December 31, 2008, $9.4 million (2007 - $9.9 million) is included in accounts payable and accrued liabilities for this plan and $8.6 million (2007 - $12.4 million) is included in other long-term liabilities. The following table reconciles the expense recorded for RTUs and PTUs.



Year ended December 31,
---------------------------------------------------------------------------
2008 2007
---------------------------------------------------------------------------
Cash general and administrative $ 8,287 $ 1,767
Non-cash unit based compensation
(included in general and administrative) (4,117) 8,007
Production, operating and maintenance expense 266 430
---------------------------------------------------------------------------
$ 4,436 $ 10,204
---------------------------------------------------------------------------
---------------------------------------------------------------------------


ii) Unit option plan

The Trust option plan (the "Plan") is administered by the Board of Directors of Provident. In October 2005, a restricted/performance unit program (see (i)) was approved. This program replaced the unit option plan. Unit options in existence continue to be outstanding until exercised or expired.

At December 31, 2008, the Trust had 967,026 options outstanding and exercisable (2007 - 1,279,169) with strike prices ranging between $10.92 and $12.14 per unit (2007 - between $10.49 and $12.14). The weighted average exercise price was $11.08 per unit (2007 - $11.04) excluding average potential reductions to the strike prices of $2.14 per unit (2007 - $1.77).

The following table reconciles the movement in the contributed surplus balance.



Year ended December 31,
---------------------------------------------------------------------------
2008 2007
---------------------------------------------------------------------------
Contributed surplus, beginning of the year $ 801 $ 1,315
Non-cash unit based compensation
(included in general and administrative) - 57
Benefit on options exercised charged to
unitholders' contributions (117) (571)
Transferred from convertible debentures equity
component on maturity (see note 8) 1 ,011 -
---------------------------------------------------------------------------
Contributed surplus, end of year $ 1,695 $ 801
---------------------------------------------------------------------------
---------------------------------------------------------------------------


12. Income taxes

In 2007, future income tax expense includes $88.4 million relating to the enactment of Bill C-52, Budget Implementation Act 2007 by the Canadian government. This bill contains legislation to tax publicly traded trusts including the Trust. As a result of this legislation, the Trust is required to record the future tax effect of the temporary differences on its flow through entities that are expected to reverse subsequent to 2010.

Although the Trust believes it will be subject to additional tax under the legislation, the estimated effective tax rate on temporary difference reversals after 2011 may change in future periods. Future technical interpretations of the legislation could occur and could materially affect management's estimate of the future income tax liability.

The amount and timing of reversals of temporary differences will also depend on the Trust's future operating results, acquisitions and dispositions of assets and liabilities, and distribution policy. A significant change in any of the preceding assumptions could materially affect the Trust's estimate of the future tax liability.

The future income tax liability is comprised of the following:



Year ended December 31,
---------------------------------------------------------------------------
2008 2007
---------------------------------------------------------------------------
Property, plant and equipment in
excess of tax value $ 378,663 $ 416,319
Asset retirement obligation (16,863) (13,360)
Financial derivative instruments (15,123) (52,050)
Non-capital losses (68,414) (47,318)
Other (10,456) (1,502)
---------------------------------------------------------------------------
$ 267,807 $ 302,089
---------------------------------------------------------------------------
---------------------------------------------------------------------------


The income tax provision differs from the expected amount calculated by applying the Trust's combined federal and provincial/state income tax rate of 30.96 percent (2007 - 32.81 percent) as follows:



Year ended December 31,
---------------------------------------------------------------------------
2008 2007
---------------------------------------------------------------------------
Expected income tax recovery, from
continuing operations $ (6,135) $ (44,030)
Increase (decrease) resulting from:
Future income tax expense relating to
enactment of Bill C-52, Budget
Implementation Act 2007 - 88,352
Goodwill impairment (permanent difference) 124,992 -
Income of the Trust and other (142,169) (64,558)
Capital taxes 3,109 3,762
Witholding tax and other (498) 3,425
Income tax rate differences (10,484) (5,193)
---------------------------------------------------------------------------
Income tax recovery, from continuing operations $ (31,185) $ (18,242)
---------------------------------------------------------------------------
---------------------------------------------------------------------------


13. 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. Put option contracts effectively create a floor price for the commodity while allowing for full participation if prices increase. Call options are contracts that allow for a commodity to be sold at a fixed price at the option of the contract holder. Costless collars are contracts that provide a floor and a ceiling price to limit the risk if prices fall and allowing upward 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. This type of derivative allows for price protection if the price falls, while still allowing some participation if the price increases. 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 insurance against lower commodity prices and product margins, as well as fluctuating interest and foreign exchange rates. 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

The fair values of financial 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 instruments are executed in liquid markets.

Management believes that financial markets currently provide adequate liquidity through price discovery and active credit-worthy counterparties for Provident to continue to execute the program in 2009.



Total
As at Held for Available Loans and Other Carrying
December 31, 2008 Trading for Sale Receivables Liabilities Value
---------------------------------------------------------------------------
Assets
Accounts
receivable $ - $ - $ 244,485 $ - $ 244,485
Financial
derivative
instruments
- current assets 16,708 - - - 16,708
- long term assets 735 - - - 735
Investments and
other long-term
assets - 1,972 12,246 - 14,218
---------------------------------------------------------------------------
$ 17,443 $ 1,972 $ 256,731 $ - $ 276,146
---------------------------------------------------------------------------
---------------------------------------------------------------------------
Liabilities
Accounts payable
and accrued
liabilities $ - $ - $ - $ 244,031 $ 244,031
Cash distributions
payable - - - 20,088 20,088
Current portion
of convertible
debentures - - - 24,871 24,871
Financial derivative
instruments
- current
liabilities 13,693 - - - 13,693
Long-term debt -
revolving term
credit facilities - - - 504,685 504,685
Long-term debt -
convertible
debentures - - - 236,123 236,123
Financial
derivative
instruments
- long-term
liabilities 58,420 - - - 58,420
Other long-term
liabilities - - - 8,572 8,572
---------------------------------------------------------------------------
$ 72,113 $ - $ - $ 1,038,370 $ 1,110,483
---------------------------------------------------------------------------
---------------------------------------------------------------------------


Except as disclosed in note 8 in 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, 2008.

The following table is a summary of the net financial derivative instruments liability:



As at As at
December 31, December 31,
---------------------------------------------------------------------------
($000s) 2008 2007
---------------------------------------------------------------------------
Provident Upstream
Crude Oil $ (12,521) $ 19,215
Natural Gas (3,285) (5,901)
Provident Midstream 70,476 261,587
Corporate - 245
---------------------------------------------------------------------------
Total $ 54,670 $ 275,146
---------------------------------------------------------------------------
---------------------------------------------------------------------------


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.

Oil and Natural Gas

Provident's risk management program employs derivative instruments, such as puts, participating swaps, costless collars and fixed price swaps, to protect a floor level of Provident's revenue on a portion of the oil and gas sold. At the same time, these instruments may enable Provident to retain various levels of participation to the extent oil and gas prices rise. Provident may also use derivative instruments for its oil and natural gas business line to protect acquisition economics.

The major identified risks for the oil and natural gas 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 five 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, 2008, 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 $2.5 million.

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.



Cdn (000's) + Change - Change
---------------------------------------------------------------------------
Provident Upstream
Crude Oil (WTI +/- $10.00 per bbl) $ (6,222) $ 6,836
Natural Gas (AECO +/- $1.00 per gj) (1,776) 1,951
---------------------------------------------------------------------------
---------------------------------------------------------------------------

Provident Midstream
Frac spread related
Crude Oil (WTI +/- $10.00 per bbl) (109,232) 109,841
Natural Gas (AECO +/- $1.00 per gj) 67,264 (67,075)
NGL's (includes
propane, butane,
natural gasoline) (Belvieu +/- US $0.15 per gal) (413) 413
Foreign Exchange
($U.S. vs $Cdn) (FX rate +/- $ 0.01) (2,299) 2,283

Inventory/margin related
Crude Oil (WTI +/- $10.00 per bbl) (13,872) 13,885
Natural Gas (AECO +/- $1.00 per gj) (78) 78
NGL's (includes
propane, butane,
natural gasoline) (Belvieu +/- US $0.15 per gal) 11,645 (11,625)
---------------------------------------------------------------------------
---------------------------------------------------------------------------


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 14.

The following table outlines the timing of the cash outflows relating to financial liabilities.



As at December 31, 2008 Payment due by period
---------------------------------------------------------------------------
Less than 1 to 3 4 to 5
($000s) Total 1 year years years
---------------------------------------------------------------------------
Accounts payable and
accrued liabilities $ 244,031 $ 244,031 $ - $ -
Cash distributions payable 20,088 20,088 - -
Current portion of
convertible debentures (2) 26,281 26,281 - -
Financial derivative
instruments - current 13,693 13,693 - -
Long-term debt - revolving
term credit facilities (1)(2) 548,761 16,784 531,977 -
Long-term debt - convertible
debentures (2) 295,322 16,184 175,849 103,289
Long-term financial
derivative instruments 58,420 - 43,147 15,273
Other long-term liabilities 8,572 - 8,572 -
---------------------------------------------------------------------------
Total $ 1,215,168 $ 337,061 $ 759,545 $ 118,562
---------------------------------------------------------------------------
---------------------------------------------------------------------------
(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.

Financial Derivative Instruments - 2008 Activity

i) Provident Upstream

a) Crude oil

In 2008, Provident paid $11.1 million (2007 - $7.9 million) to settle various oil market based contracts on an aggregate volume of 1.6 million barrels (2007 - 1.6 million barrels). The estimated value of contracts in place if settled at market prices at December 31, 2008 would have resulted in an opportunity gain of $12.5 million (2007 - $19.2 million opportunity cost).

b) Natural Gas

In 2008, Provident received nil (2007 - $9.6 million) to settle various natural gas market based contracts on an aggregate of 10.9 million gigajoules ("gj") (2007 - 16.7 million gj's). The estimated value of contracts in place if settled at market prices at December 31, 2008 would have resulted in an opportunity gain of $3.3 million (2007 - $5.8 million).

ii) Provident Midstream

In 2008, Provident paid $135.6 million (2007 - received $17.9 million) to settle Midstream oil market based contracts on an aggregate volume of 4.2 million barrels (2007 - 1.2 million barrels) and paid $17.0 million (2007 - $48.7 million) to settle Midstream natural gas market based contracts on an aggregate volume of 26.8 million gj's (2007 - 25.3 million gj's). In addition, Provident received $25.9 million (2007 - paid $48.2 million) to settle Midstream NGL market based contracts on an aggregate volume of 2.3 million barrels (2007 - 7.2 million barrels).

Provident also received $5.4 million (2007 - $4.6 million) to settle Midstream-related foreign exchange contracts, and received $2.4 million (2007 - nil) to settle various electricity-based contracts. The estimated value of contracts in place if settled at market prices at December 31, 2008 would have resulted in an opportunity cost of $70.5 million (2007 - $261.6 million).

iii) Corporate

a) Foreign exchange contracts

In 2008, Provident received $26.8 million to settle various corporate-related foreign exchange contracts (2007 - $1.3 million). Realized gains and losses on corporate-related foreign exchange contracts are included in foreign exchange (gain) loss and other on the consolidated statement of operations and are allocated to the reporting segments for segmented reporting purposes. The estimated value of contracts in place if settled at foreign exchange rates at December 31, 2008 would have resulted in an opportunity cost of nil (2007 - $0.1 million).

The contracts in place at December 31, 2008 are summarized in the following tables:



Provident Upstream

Volume
Year Product (Buy)/Sell Terms Effective Period
---------------------------------------------------------------------------
2009 Crude Oil 2,000 Bpd WCS Blend at 80% January 1 -
of US$ WTI March 31
2,283 Bpd Participating Swap US $62.36 January 1 -
per bbl (Participation December 31
Range 52% to 90% above the
floor price)
Natural
Gas 5,000 Gjpd Puts Cdn $9.29 per gj January 1 -
March 31
4,871 Gjpd Participating Swap Cdn $6.93 January 1 -
per gj (Participation December 31
Range 20% to 95% above the
floor price)
---------------------------------------------------------------------------
---------------------------------------------------------------------------

Provident Midstream
Volume
Year Product (Buy)/Sell Terms Effective Period
---------------------------------------------------------------------------
2009 Crude Oil 7,038 Bpd Cdn $74.20 per bbl January 1 -
December 31
750 Bpd US $65.97 per bbl January 1 -
December 31
2,973 Bpd US $85.16 per bbl (12) January 1 -
December 31
(1,052) Bpd Cdn $70.21 per bbl (10) January 1 -
November 30
(420) Bpd US $88.30 per bbl (9) January 1 -
March 31
323 Bpd US $57.78 per bbl (11) May 1 - May 31
2,748 Bpd Costless Collar US $65.27 January 1 -
floor, US $70.23 ceiling December 31
621 Bpd Participating Swap Cdn September 1 -
$78.27 per bbl (Average December 31
Participation 38% above
the floor price)
1,052 Bpd Participating Swap US July 1 -
$71.31 per bbl (Average November 30
Participation 54% above
the floor price)
Natural
Gas (60,255) Gjpd Cdn $8.15 per gj January 1 -
December 31
2,500 Gjpd Cdn $6.56 per gj (11) January 1 -
January 31
(3,477) Gjpd Participating Swap Cdn July 1 -
$7.86 per gj (Average December 31
Participation 33% below
the ceiling price)
(2,810) Gjpd Costless Collar Cdn $6.20 September 1 -
floor, Cdn $7.10 ceiling October 31
Propane 760 Bpd US $1.32 per gallon (5) (11) January 1 -
March 31
600 Bpd US $1.265 per gallon (9) January 1 -
March 31
333 Bpd US $0.99 per gallon (6) (11) January 1 -
March 31
Natural
Gasoline (2,973) Bpd US $1.74 per gallon (12) January 1 -
December 31
Normal
Butane (1,473) Bpd US $0.76 per gallon (12) April 1 -
December 31
Foreign
Exchange Sell US $6,432,441 per January 1 -
month @ 1.1117 (13) December 31
Sell US $1,055,833 per January 1 -
month @ 1.099 (13) June 30
Sell US $1,972,561 per July 1 -
month @ 1.0244 (13) August 31
Sell US $596,166 per July 1 -
month @ 0.9815 (13) October 31
Sell US $1,686,650 per September 1 -
month @ 0.9622 (13) October 31
Sell US $1,809,600 per November 1 -
month @ 1.0098 (13) November 30

2010 Crude Oil 6,238 Bpd Cdn $73.19 per bbl January 1 -
December 31
500 Bpd US $66.65 per bbl January 1 -
December 31
1,750 Bpd Costless Collar US $61.63 January 1 -
floor, US $66.56 ceiling December 31
464 Bpd Participating Swap Cdn January 1 -
$77.01 per bbl (Average December 31
Participation 37% above
the floor price)
860 Bpd Participating Swap US January 1 -
$74.89 per bbl (Average December 31
Participation 48% above
the floor price)
Natural
Gas (47,181) Gjpd Cdn $7.83 per gj January 1 -
December 31
(5,756) Gjpd Participating Swap Cdn January 1 -
$7.77 per gj (Average December 31
Participation 28% below
the ceiling price)
Normal
Butane (1,500) Bpd US $0.76 per gallon (12) January 1 -
March 31
Foreign
Exchange Sell US $4,773,059 per January 1 -
month @ 1.1110 (13) December 31
Sell US $582,821 per January 1 -
month @ 1.0159 (13) August 31
Sell US $1,420,921 per July 1 -
month @ 0.9781 (13) August 31
Sell US $587,903 per July 1 -
month @ 1.0165 (13) November 30
Sell US $2,254,103 per September 1 -
month @ 0.9578 (13) October 31
Sell US $2,394,058 per September 1 -
month @ 1.0154 (13) November 30
Sell US $629,673 per November 1 -
month @ 1.0165 (13) December 31
2011 Crude Oil 5,534 Bpd Cdn $71.73 per bbl January 1 -
December 31
1,005 Bpd Costless Collar US $60.64 January 1 -
floor, US $73.45 ceiling September 30
416 Bpd Participating Swap Cdn October 1 -
$84.38 per bbl (Average December 31
Participation 25% above
the floor price)
250 Bpd Participating Swap US January 1 -
$63.00 per bbl (Average December 31
Participation 64% above
the floor price)
Natural
Gas (37,595) Gjpd Cdn $7.32 per gj January 1 -
December 31
(2,337) Gjpd Participating Swap Cdn October 1 -
$8.28 per gj (Average December 31
Participation 25% below
the ceiling price)
Foreign
Exchange Sell US $479,063 per January 1 -
month @ 0.9725 (13) December 31
Sell US $980,417 per January 1 -
month @ 1.0805 (13) June 30
Sell US $3,588,000 per July 1 -
month @ 1.0918 (13) September 30
2012 Crude Oil 3,637 Bpd Cdn $72.57 per bbl January 1 -
December 31
1,445 Bpd Participating Swap Cdn February 1 -
$85.19 per bbl (Average December 31
Participation 27% above
the floor price)
1,352 Bpd Participating Swap US March 1 -
$72.22 per bbl (Average December 31
Participation 51% above
the floor price)
Natural
Gas (25,717) Gjpd Cdn $7.24 per gj January 1 -
December 31
(9,318) Gjpd Participating Swap Cdn February 1 -
$8.55 per gj (Average December 31
Participation 28% below
the ceiling price)
Foreign
Exchange Sell US $2,016,783 per March 1 -
month @ 1.0119 (13) March 31
Sell US $1,041,721 per April 1 -
month @ 0.9413 (13) October 31
Sell US $681,260 per May 1 -
month @ 0.9850 (13) October 31
Sell US $1,437,986 per July 1 -
month @ 0.9659 (13) December 31
Sell US $1,634,227 per October 1 -
month @ 0.9829 (13) December 31
Sell US $1,420,538 per November 1 -
month @ 0.9995 (13) December 31
2013 Crude Oil 250 Bpd Cdn $75.32 per bbl January 1 -
January 31
1,250 Bpd Participating Swap Cdn January 1 -
$84.90 per bbl (Average March 31
Participation 25% above
the floor price)
758 Bpd Participating Swap US January 1 -
$85.62 per bbl (Average March 31
Participation 30% above
the floor price)
Natural
Gas (7,025) Gjpd Cdn $7.19 per gj January 1 -
January 31
(9,524) Gjpd Participating Swap Cdn January 1 -
$8.87 per gj (Average March 31
Participation 22% below
the ceiling price)
Foreign
Exchange Sell US $1,651,990 per January 1 -
month @ 0.9829 (13) January 31
Sell US $1,397,250 per January 1 -
month @ 0.9995 (13) March 31
---------------------------------------------------------------------------
(1) The above table represents a number of transactions entered into over
an extended period of time.
(2) Natural gas contracts are settled against AECO monthly index.
(3) Crude Oil contracts are settled against NYMEX WTI calendar average.
(4) WCS contracts are settled against NYMEX WTI calendar average plus the
monthly index for physical WCS (quoted as a differential to WTI) by
NetThruPut Inc.
(5) Propane contracts are settled against Belvieu C3 TET.
(6) Propane contracts are settled against Conway In-Well C3.
(7) Normal Butane contracts are settled against Belvieu NC4 TET.
(8) Natural Gasoline contracts are settled against Belevieu NON-TET
Natural Gasoline.
(9) Conversion of Crude Oil BTU contracts to liquids.
(10) BTU re-balancing of Crude Oil contracts.
(11) Midstream inventory price stabilization contracts.
(12) Midstream margin contracts.
(13) US Dollar forward contracts are settled against the Bank of Canada
noon rate average.


14. 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, 2008 and December 31, 2007 was as follows:



As at As at
December 31, December 31,
---------------------------------------------------------------------------
($000s) 2008 2007
---------------------------------------------------------------------------
Working capital surplus (1) $ (39,041) $ (58,732)
Long-term debt (including current portion) 765,679 1,199,634
---------------------------------------------------------------------------
Net debt 726,638 1,140,902
Unitholders' equity 1,636,347 1,708,665
---------------------------------------------------------------------------
Total capitalization $ 2,362,985 $ 2,849,567
---------------------------------------------------------------------------
---------------------------------------------------------------------------

Net debt to total capitalization 31% 40%
---------------------------------------------------------------------------
---------------------------------------------------------------------------
(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 shareholders 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 each of the next two years, as follows:



---------------------------------------------------------------------------
($ billions) Annual Cumulative
---------------------------------------------------------------------------
Normal growth capital allowed in:
2009 (1) 0.6 2.3
2010 0.5 2.8
---------------------------------------------------------------------------
(1) The Trust's allowed growth capital prior to 2009 was approximately
$1.7 billion.


If the maximum equity growth allowed is exceeded, the Trust may be subject to trust taxation prior to 2011. In 2007 and 2008, the Trust issued equity amounting to $552.0 million.

15. 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 is accounted for as discontinued operations and comparative figures have been reclassified to conform with this presentation.

In June 2008, the Trust sold a portion of the USOGP business, consisting of its 22 percent interest in BreitBurn Energy Partners, L.P. (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 has recorded a gain on sale of $187.9 million and $127.7 million in current tax expense related to this transaction. Also recorded was a realized foreign exchange loss of $30.3 million, representing the recognition of the related portion of the foreign exchange loss in accumulated other comprehensive income, which was generated since inception in 2006. These amounts are recorded as part of net income from discontinued operations for the year ended December 31, 2008.

In August 2008, the Trust sold the remaining portion of the USOGP business, comprised of an approximate 96 percent interest in BreitBurn Energy Company 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 has recorded a gain on sale of $75.7 million and $66.9 million in current tax expense related to this transaction. Also recorded was a realized foreign exchange loss of $26.8 million, representing the recognition of the related portion of the foreign exchange loss in accumulated other comprehensive income, which was generated since acquisition in 2004. These amounts are recorded as part of net income from discontinued operations for the year ended December 31, 2008.

During 2008, the Trust made tax installment payments for the amounts relating to the sales of the MLP, BreitBurn GP LLC and BreitBurn Energy Company L.P.

Quicksilver Resources Inc. ("Quicksilver") filed a lawsuit on October 31, 2008 against the MLP, certain of its directors (including three Provident nominees), and Provident. 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. The litigation is in its very early stages, and it is not possible at this time to assess the potential exposure of Provident in the event of an adverse verdict. Provident believes the claims made against it in the lawsuit are without merit and will vigorously defend itself and its named director nominees against these claims.

The following tables show the net assets of discontinued operations and information about net income from USOGP.



As at As at
Balance sheets December 31, December 31,
Canadian dollars (000s) 2008 2007
---------------------------------------------------------------------------
Assets
Current assets $ - $ 93,578
---------------------------------------------------------------------------
Property, plant and equipment - 2,008,549
Other long-term assets - 19,055
---------------------------------------------------------------------------
- 2,027,604
---------------------------------------------------------------------------
$ - $ 2,121,182
---------------------------------------------------------------------------
---------------------------------------------------------------------------
Liabilities
Current liabilities
Accounts payable and accrued liabilities $ - $ 77,244
Financial derivative instruments - 37,437
---------------------------------------------------------------------------
- 114,681
---------------------------------------------------------------------------
Long-term debt - revolving term
credit facilities - 368,836
Long-term financial derivative instruments - 66,382
Asset retirement obligation and
other long-term liabilities - 45,373
Future income taxes - 147,911
---------------------------------------------------------------------------
- 628,502
---------------------------------------------------------------------------
Non-controlling interests - 1,100,136
---------------------------------------------------------------------------
Net Assets - discontinued operations $ - $ 277,863
---------------------------------------------------------------------------
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Net income from discontinued operations Year ended December 31,
---------------------------------------------------------------------------
Canadian dollars (000's) 2008 2007
---------------------------------------------------------------------------
Revenue $ 303,146 $ 246,760
---------------------------------------------------------------------------
Loss from discontinued operations before taxes,
non-controlling interests, dilution gain and
impact of sale of discontinued operations (237,233) (90,748)
Dilution gain - 260,324
Gain on sale of discontinued operations 263,618 -
Foreign exchange loss related to sale
of discontinued operations (57,062) -
Current and withholding tax expense (178,708) (10)
Future income tax recovery (expense) 151,975 (58,843)
Non-controlling interests 203,434 35,666
---------------------------------------------------------------------------

Net income from discontinued operations $ 146,024 $ 146,389
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16. Commitments

Provident has office lease commitments that extend through June 2022. Future minimum lease payments for the following five years are: 2009 - $8.7 million; 2010 - $8.5 million; 2011 - $8.5 million; 2012 - $8.8 million, and 2013 - $9.0 million.

In relation to the midstream services and marketing segment, Provident is committed to minimum lease payments under the terms of various rail tank car leases for the following five years: 2009 - $9.3 million; 2010 - $7.0 million; 2011 - $5.6 million; 2012 - $3.1 million and 2013 - $0.8 million. Additionally, under an arrangement to use a third party interest in the Younger plant, Provident has a commitment to make payments calculated with reference to a number of variables including return on capital. Payments for the next five years are estimated as follows: 2009 - $4.3 million; 2010 - $4.1 million; 2011 - $3.9 million; 2012 - $3.8 million and 2013 - $3.6 million.

17. Segmented information

The Trust's business activities are conducted through two business segments: Canadian oil and natural gas production ("COGP" or "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 and storage of natural gas liquids, and marketing of natural gas liquids.

Geographically the Trust operates in Canada in the oil and gas production business segment and in Canada and the USA in the Midstream business.



Year ended December 31, 2008
-----------------------------------------
Provident Provident
Upstream Midstream (1) Total
---------------------------------------------------------------------------
Revenue
Gross production revenue $ 681,336 $ - $ 681,336
Royalties (123,140) - (123,140)
Product sales and service revenue - 2,589,518 2,589,518
Realized loss on financial
derivative instruments (11,102) (118,917) (130,019)
---------------------------------------------------------------------------
547,094 2,470,601 3,017,695
---------------------------------------------------------------------------
Expenses
Cost of goods sold - 2,206,427 2,206,427
Production, operating
and maintenance 138,173 14,938 153,111
Transportation 16,320 20,800 37,120
Foreign exchange (gain)
loss and other 2,917 (19,853) (16,936)
General and administrative 36,191 35,528 71,719
---------------------------------------------------------------------------
193,601 2,257,840 2,451,441
---------------------------------------------------------------------------
Earnings before interest, taxes,
depletion, depreciation, accretion
and other non-cash items 353,493 212,761 566,254
Other revenue
Unrealized gain (loss) on financial
derivative instruments 30,230 191,238 221,468
---------------------------------------------------------------------------
Other expenses
Depletion, depreciation
and accretion 304,909 38,406 343,315
Goodwill impairment 416,890 - 416,890
Interest on bank debt 9,022 27,066 36,088
Interest and accretion on
convertible debentures 4,986 14,958 19,944
Unrealized foreign exchange (gain)
loss and other 4,296 (8,188) (3,892)
Non-cash unit based compensation (2,199) (1,918) (4,117)
Internal management charge (689) - (689)
Capital tax expense 3,109 - 3,109
Current and withholding tax
(recovery) expense (212) (4,317) (4,529)
Future income tax (recovery)
expense (50,339) 20,574 (29,765)
---------------------------------------------------------------------------
689,773 86,581 776,354
---------------------------------------------------------------------------
Net income (loss) for the year
from continuing operations $ (306,050) $ 317,418 $ 11,368
Net income from discontinued
operations (note 15) 146,024
---------------------------------------------------------------------------
Net income for the year $ 157,392
---------------------------------------------------------------------------
---------------------------------------------------------------------------
(1) Included in the Provident 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, 2008
------------------------------------------------
Provident Provident
Upstream Midstream Total
---------------------------------------------------------------------------
Selected balance sheet items
Capital assets
Property, plant and
equipment net $ 1,731,331 $ 749,172 $ 2,480,503
Intangible assets - 158,336 158,336
Goodwill - 100,409 100,409
Capital expenditures
Capital Expenditures 209,147 37,800 246,947
Oil and gas property
acquisitions, net 24,181 - 24,181
Goodwill additions (impairments) (416,890) - (416,890)
Working capital
Accounts receivable 60,839 183,646 244,485
Petroleum product inventory - 46,160 46,160
Accounts payable and
accrued liabilities 114,152 129,879 244,031
Long-term debt - revolving
term credit facilities 126,171 378,514 504,685
Long-term debt - convertible
debentures 59,031 177,092 236,123
Financial derivative instruments
(asset) liability $ (15,806) $ 70,476 $ 54,670
---------------------------------------------------------------------------
---------------------------------------------------------------------------



Year ended December 31, 2007
----------------------------------------
Provident Provident
Upstream Midstream (1) Total
---------------------------------------------------------------------------
Revenue
Gross production revenue $ 454,179 $ - $ 454,179
Royalties (87,046) - (87,046)
Product sales and service revenue - 1,958,372 1,958,372
Realized gain (loss) on financial
derivative instruments 1,728 (74,474) (72,746)
---------------------------------------------------------------------------
368,861 1,883,898 2,252,759
---------------------------------------------------------------------------
Expenses
Cost of goods sold - 1,594,639 1,594,639
Production, operating
and maintenance 112,387 14,094 126,481
Transportation 8,193 16,825 25,018
Foreign exchange (gain)
loss and other (573) 3,996 3,423
General and administrative 27,102 28,669 55,771
---------------------------------------------------------------------------
147,109 1,658,223 1,805,332
---------------------------------------------------------------------------
Earnings before interest, taxes,
depletion, depreciation, accretion
and other non-cash items 221,752 225,675 447,427
Other revenue
Unrealized gain (loss) on financial
derivative instruments (21,324) (192,920) (214,244)
---------------------------------------------------------------------------
Other expenses
Depletion, depreciation
and accretion 256,723 44,388 301,111
Goodwill impairment - - -
Interest on bank debt 11,055 33,166 44,221
Interest and accretion on
convertible debentures 3,672 11,015 14,687
Unrealized foreign exchange (gain)
loss and other 779 - 779
Non-cash unit based compensation 3,698 4,366 8,064
Internal management charge (1,482) - (1,482)
Capital tax expense 3,762 - 3,762
Current and withholding tax
(recovery) expense (254) 6,606 6,352
Future income tax (recovery)
expense (2) (122,590) 94,234 (28,356)
---------------------------------------------------------------------------
155,363 193,775 349,138
---------------------------------------------------------------------------
Net income (loss) for the year
from continuing operations $ 45,065 $ (161,020) $ (115,955)
Net income from discontinued
operations (note 15) 146,389
---------------------------------------------------------------------------
Net income for the year $ 30,434
---------------------------------------------------------------------------
---------------------------------------------------------------------------
(1) Included in the Provident Midstream segment is product sales and
service revenue of $297.8 million associated with U.S. operations.
(2) Future income tax (recovery) expense includes a charge of $88.4 million
relating to the enactment of Bill C-52, Budget Implementation Act 2007
by the Canadian government.



As at and for the year ended December 31, 2007
------------------------------------------------
Provident Provident
Upstream Midstream Total
---------------------------------------------------------------------------
Selected balance sheet items
Capital assets
Property, plant and
equipment net $ 1,773,209 $ 737,062 $ 2,510,271
Intangible assets - 171,793 171,793
Goodwill 416,890 100,409 517,299
Capital expenditures
Capital Expenditures 146,209 31,904 178,113
Corporate acquisitions 469,795 - 469,795
Oil and gas property
acquisitions, net 13,050 - 13,050
Goodwill additions (impairments) 85,946 - 85,946
Working capital
Accounts receivable 75,292 262,813 338,105
Petroleum product inventory - 84,638 84,638
Accounts payable and
accrued liabilities 132,650 214,574 347,224
Long-term debt - revolving
term credit facilities 230,999 692,997 923,996
Long-term debt - convertible
debentures 64,110 192,330 256,440
Financial derivative instruments
(asset) liability $ 13,559 $ 261,587 $ 275,146
---------------------------------------------------------------------------
---------------------------------------------------------------------------


18. Reconciliation of financial statements to United States generally accepted accounting principles (U.S. GAAP)

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



Consolidated Statements of Earnings - U.S. GAAP

For the year ended December 31, (Cdn $000s) 2008 2007
---------------------------------------------------------------------------
Net income as reported $ 157,392 $ 30,434
Adjustments
Depletion, depreciation and accretion (a) 79,558 65,306
Depletion, depreciation and accretion
other (a) (813,983) (181,551)
Goodwill impairment (g) 416,890 -
General and administrative (d) - 483
Future income tax recovery (a) (b) 180,161 25,371
Accretion on convertible debentures (e) 3,010 2,802
Gain on sale of discontinued operations (8,983) -
Other adjustments to net income from
discontinued operations 2,976 2,538
---------------------------------------------------------------------------
Net income (loss) - U.S. GAAP $ 17,021 $ (54,617)
Other comprehensive income (loss) 67,005 (26,000)
---------------------------------------------------------------------------
Comprehensive income (loss) 84,026 (80,617)
---------------------------------------------------------------------------
---------------------------------------------------------------------------
Net loss from continuing operations
per unit - basic and diluted $ (0.48) $ (0.89)
Net income (loss) per unit -
basic and diluted $ 0.07 $ (0.24)
---------------------------------------------------------------------------
---------------------------------------------------------------------------


Condensed Consolidated Balance Sheet
As at December 31, (Cdn$ 000s) 2008 2007
---------------------------------------------------------------------------
Canadian U.S. Canadian U.S.
GAAP GAAP GAAP GAAP
---------------------------------------------------------------------------
Assets
Deferred financing charges (e) $ - $ 4,921 $ - $ 8,266
Property, plant
and equipment (a) 2,480,503 1,198,561 2,510,271 1,962,754
Goodwill (g) 100,409 517,299 517,299 517,299
Long-term assets held
for sale - USOGP - - 2,027,604 2,046,025
Liabilities and unitholders' equity
Current portion of convertible
debentures (e) 24,871 25,109 19,198 19,931
Long-term debt - revolving
term credit facilities (e) 504,685 504,912 923,996 925,266
Long-term debt - convertible
debentures (e) 236,123 248,979 256,440 274,113
Future income tax liability
(asset) (a) (b) 267,807 (68,733) 302,089 145,710
Long-term liabilities held
for sale - USOGP - - 628,502 638,021
Non-controlling interests - - 1,100,136 1,103,031
Units subject to redemption (f) - 1,381,352 - 2,308,273
Unitholders' equity (e) (f) 1,638,530 (279,734) 1,777,853 (926,961)
---------------------------------------------------------------------------
---------------------------------------------------------------------------


(a) Under the Canadian cost recovery ceiling test the recoverability of a cost centre is tested by comparing the carrying value of the cost centre to the sum of the undiscounted proved reserve cash flows expected from the cost centre using future price estimates. If the carrying value is not recoverable, the cost centre is written down to its fair value determined by comparing the future cash flows from the proved plus probable reserves discounted at the Trust's risk free interest rate. Any excess carrying value of the assets on the balance sheet above fair value would be recorded in depletion, depreciation and accretion expense as a permanent impairment. Under U.S. GAAP, companies utilizing the full cost method of accounting for oil and natural gas activities perform a ceiling test on each cost centre using discounted future net revenue from proved oil and natural gas reserves discounted at 10 percent. Prices used in the U.S. GAAP ceiling tests are those in effect at year-end. The amounts recorded for depletion and depreciation have been adjusted in the periods as a result of differences in write down amounts recorded pursuant to U.S. GAAP compared to Canadian GAAP.

In computing its consolidated net earnings for U.S. GAAP purposes, the Trust recorded additional depletion in 2008 of $814.0 million (2007 - $181.6 million) and a related future income tax recovery of $214.3 million (2007 - $52.2 million) as a result of the application of the ceiling test. These charges were not required under the Canadian GAAP ceiling tests.

(b) The Canadian liability method of accounting for income taxes in CICA handbook Section 3465 "Income taxes" is similar to the United States FAS 109, "Accounting for Income Taxes", which requires the recognition of deferred tax assets and liabilities for the expected future tax consequences of events that have been recognized in Provident's financial statements or tax returns. Pursuant to U.S. GAAP, enacted tax rates are used to calculate future taxes, whereas Canadian GAAP uses substantively enacted rates.

In July 2006, the FASB issued FIN 48, "Accounting for Uncertainty in Income Taxes". The interpretation creates a single model to address uncertainty in tax positions and clarifies the accounting for income taxes by prescribing the minimum recognition threshold a tax position is required to meet before being recognized in the financial statements. The statement also provides guidance on de-recognition, measurement, classification, interest and penalties, accounting in interim periods, disclosures and transitions as well as specifically scopes out accounting for contingencies. FIN 48 is effective for fiscal years beginning after December 15, 2006. The adoption of this statement has not resulted in a Canadian to U.S. GAAP difference.

(c) The consolidated statements of cash flows and operations and accumulated income are prepared in accordance with Canadian GAAP and conform in all material respects with U.S. GAAP except for the following;

(i) Canadian GAAP allows for the presentation of funds flow from operations in the consolidated statement of cash flows. This total cannot be presented under U.S. GAAP.

(ii) U.S. GAAP requires disclosure on the consolidated statement of operations when depreciation, depletion and amortization are excluded from cost of goods sold. This disclosure has not been noted on the face of the consolidated statement of operations.

(d) Under Canadian GAAP, Provident follows CICA handbook Section 3870 "Stock-based compensation and other stock-based payments" which provides for the presentation and measurement of cash-settled unit-based compensation as liabilities based on the intrinsic value each period. Under U.S. GAAP FAS 123R "Share-based payments", public entities are required to measure liability awards based on the award's fair value re-measured at each reporting date until the date of settlement. Compensation cost for each period is based on the change in the fair value of the units for each reporting period and is recognized over the vesting period.

(e) Under Canadian GAAP Provident applies EIC Abstract 164 "Convertible and other instruments with embedded derivatives" to account for the convertible debentures. Under U.S. GAAP, the convertible debentures are disclosed as long-term debt at their face value versus Canadian GAAP that requires discounting of the convertible debentures, accretion expense to represent the unwinding of the discounted convertible debentures and a value assigned within equity to the conversion feature component of the convertible debentures. In addition, U.S. GAAP requires debt issue costs to be reported as deferred charges on the consolidated balance sheet. In December 2008, the Trust repaid $19.9 million to the holders of its 8.75 percent convertible debentures. Upon maturity, the Trust transferred $1.0 million of the equity component to contributed surplus under Canadian GAAP. Under U.S. GAAP, this amount would not have been transferred as convertible debentures are recorded in long-term debt at face value.

(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. Decreases in redemption value in the period (2008 - $982.6 million; 2007 - $505.1 million) are recorded to accumulated earnings. Under Canadian GAAP, such equity instruments are considered to be permanent equity and are presented as unitholder's equity. The Trust's units have a redemption feature, which qualify them to be considered under this guidance.

(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 a $416.9 million impairment being recorded. 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.

Recent U.S. Accounting Pronouncements

Non-controlling interests in consolidated financial statements

In December 2007, the FASB issued FAS 160 "Non-controlling interests in Consolidated Financial Statements." FAS 160 requires the ownership interests in subsidiaries held by parties other than the parent be clearly presented in the consolidated balance sheet within equity, but separate from the parent's equity and the amount of consolidated net income attributable to the parent and the non-controlling interest be clearly identified and presented on the face of the consolidated statement of operations. Changes in the parent's ownership interest should be accounted for consistently as equity transactions. If a subsidiary is deconsolidated, any retained non-controlling equity investment in the former subsidiary should be initially recorded at fair value and the gain or loss on the deconsolidation of the subsidiary is measured using the fair value of any non-controlling equity investment rather than the carrying amount of the retained investment. This statement is effective for fiscal years, and interim periods, beginning on or after December 15, 2008. The Trust does not expect the adoption of this statement to have a material impact on its financial statements.

Business combinations

In December 2007, the FASB revised FAS 141 "Business Combinations." FAS 141 establishes how an acquirer recognizes and measures in its financial statements the identifiable assets and liabilities as well as any non-controlling interest in the acquiree, how an acquirer should recognize and measure goodwill acquired in the business combination or a gain from a bargain purchase, and how an acquirer determines what information to disclose to enable users of the financial statements to evaluate the nature and financial effects of the business combination. The statement specifically addresses the treatment of acquisition costs separate from the acquisition as opposed to including them as part of the acquisition purchase price. This statement applies prospectively to business combinations for which the acquisition date is on or after the beginning of the first annual reporting period beginning on or after December 15, 2008. The adoption of this statement will impact any future business combination with an acquisition date after January 1, 2009.

The fair value option for financial assets and financial liabilities

In February 2007, the FASB issued FAS 159 "The Fair Value Option for Financial Assets and Financial Liabilities." FAS 159 permits entities to chose to measure eligible items at fair value at specified election dates. The entity would record gains and losses on items for which the fair value option has been elected in earnings at each subsequent reporting date. This statement is effective as of the beginning of an entity's first fiscal year that begins after November 15, 2007. The adoption of this statement has not had a material impact on the Trust's financial statements.

Fair value measurement

In September 2006, the FASB issued FAS 157 "Fair value measurement." FAS 157 defines fair value, establishes a framework for measuring fair value in generally accepted accounting principles and expands disclosures about fair value measurements. This statement does not require any new fair value measurements. Fair value is defined in this statement as the exchange price, which is the price in an orderly transaction between market participants to sell the asset or transfer the liability in the market in which the reporting entity would transact for the asset or liability, that is, the principal or most advantageous market for the asset or liability. The statement is effective for financial statements issued for fiscal years beginning after November 15, 2007, and interim periods of those fiscal years. The 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 impact the reserves in the Trust's accounting for depletion and its calculation of the ceiling test under US GAAP. These revisions are effective for filings made on or after January 1, 2010 and will be applied prospectively with no retroactive restatement.

Contact Information

  • Provident Energy Trust
    Investor and Media Contact:
    Dallas McConnell
    Manager, Investor Relations
    Phone: (403) 231-6710
    Email: info@providentenergy.com
    or
    Corporate Head Office:
    2100, 250 - 2nd Street SW
    Calgary, Alberta T2P 0C1
    (403) 296-2233 or Toll Free: 1-800-587-6299
    (403) 264-5820 (FAX)
    Website: www.providentenergy.com