Provident Energy Trust
TSX : PVE.UN
NYSE : PVX

Provident Energy Trust

March 19, 2008 07:30 ET

Provident Energy Announces 2007 Year-End and Fourth Quarter Results and 2007 Reserves Information

CALGARY, ALBERTA--(Marketwire - March 19, 2008) - 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 delivered another year of strong financial and operating results in 2007," said Provident President and Chief Executive Officer, Tom Buchanan. "Our diverse portfolio of assets delivered solid performance in the face of a volatile commodity price environment, stronger Canadian dollar, tighter equity and debt capital markets, and continued challenges related to government policy. We maintained stable distributions of $1.44 ($0.12 per month) for the fourth consecutive year. We strengthened our upstream business substantially in 2007 with the Capitol and Triwest acquisitions in Canada and four asset acquisitions in the U.S. including the $1.5 billion asset acquisition from Quicksilver Resources Inc. The Midstream business unit had another outstanding year, delivering record EBITDA of $226 million."

Highlights

- Consolidated funds flow from operations increased 8 percent to $468 million ($2.04 per unit) compared to $433 million ($2.20 per unit) in 2006. Consolidated earnings before interest, taxes, depletion, depreciation, accretion and other non-cash items (EBITDA) was $545 million in 2007, an increase of 10 percent compared to $496 million in 2006.

- The payout ratio in the fourth quarter of 2007 was strong at 57 percent, down from 64 percent in the fourth quarter of 2006. Full year payout ratio in 2007 was 77 percent, up from 67 percent in 2006.

- Consolidated funds flow from operations in the fourth quarter of 2007 increased 45 percent to $178 million ($0.72 per unit) compared to $123 million ($0.58 per unit) in the fourth quarter of 2006. Consolidated EBITDA in the fourth quarter of 2007 was $196 million, an increase of 39 percent compared to $141 million in the fourth quarter of 2006.

- Consolidated upstream production increased 22 percent to 38,600 barrels of oil equivalent per day (boed) in 2007, up from 31,700 boed in 2006. Canadian oil and gas production increased 10 percent to 26,500 boed in 2007, up from 24,000 boed in 2006, with a balanced production profile of 58 percent natural gas and 42 percent crude oil and natural gas liquids. In the fourth quarter of 2007, consolidated production averaged 48,200 boed compared to 33,800 boed in the fourth quarter of 2006 reflecting the acquisitions made in both Canada and the United States.

- Midstream EBITDA in 2007 was a record $226 million, up from $220 million in 2006, reflecting a favourable price environment and strong operating and marketing performance. In the fourth quarter of 2007, Midstream delivered EBITDA of $89 million, up 20 percent from $74 million in the fourth quarter of 2006.

- Consolidated upstream proved plus probable reserve life index (RLI) increased from 12.4 years to 16.9 years, reflecting the increasing quality of the assets and the sustainability of the Trust. Provident's Canadian proved plus probable RLI increased 24 percent to 9.7 years. Factoring in the long-life midstream assets, Provident's economic life on a consolidated basis is now approximately 18.5 years.

- On a consolidated basis, Provident drilled 159 net wells with a 99 percent success rate while in Canada 103 net wells were drilled with a 98 percent success rate. Provident's drilling activities in 2007 were focused primarily on crude oil.

- Consolidated proved plus probable oil and gas reserves increased 111 percent to 322 million barrels of oil equivalent (boe). Canadian proved plus probable oil and gas reserves increased 37 percent to 101 million boe.

- Consolidated reserve additions including acquisitions and revisions, were 13 times greater than current year production. In Canada, reserve additions were 3.8 times greater than current year production.

- Consolidated finding, development and acquisition (FD&A) costs including revisions and future development capital (FDC) improved to $15.18 per boe of proved plus probable reserves, compared to $22.04 per boe in 2006. The three year average FD&A costs including revisions and FDC were $16.05 per boe of proved plus probable reserves in 2007 compared to $13.26 per boe in 2006.

- 2007 Canadian FD&A costs including revisions and FDC were $23.31 per boe of proved plus probable reserves compared to $23.04 per boe in 2006. The three-year average Canadian FD&A costs including revisions and FDC were $24.48 per boe of proved plus probable reserves in 2007 compared to $23.60 per boe in 2006. These figures reflect the high value oil acquisitions completed in 2007. Canadian finding and development (F&D) costs for proved plus probable additions including revisions and FDC were $24.42 per boe in 2007 compared to $23.99 per boe in 2006. The three-year average Canadian F&D costs for proved plus probable additions including revisions and FDC were $20.82 per boe in 2007 compared to $17.27 per boe in 2006.

Outlook

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

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

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

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

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

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

Provident's audited financial statements for the year ended December 31, 2007, annual and fourth quarter MD&A, and complete reserves information were filed today on the System for Electronic Document Analysis and Retrieval (SEDAR) (www.sedar.com), and can also be found on Provident's website, at www.providentenergy.com, under the heading "investors."

This press release does not constitute and is not intended to be legal or tax advice to any particular holder or potential holder of Provident units. Holders or potential holders of Provident units are urged to consult their own legal and tax advisors as to their particular income tax consequences of holding Provident units.

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 and the United States. 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

Three months ended Year ended
Consolidated December 31, December 31,
----------------------------------------------------------------------------
($ 000s
except per
unit data) 2007 2006 % Change 2007 2006 % Change
----------------------------------------------------------------------------

Revenue (net
of royalties
and financial
derivative
instruments) $ 541,884 $548,086 (1) $2,167,276 $2,187,253 (1)
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Funds flow
from COGP
operations
(1) $ 58,667 $ 48,574 21 $ 204,252 $ 185,328 10
Funds flow from
USOGP
operations (1) 41,787 13,573 208 85,571 62,970 36
Funds flow from
Midstream
operations (1) 77,109 60,532 27 178,432 184,366 (3)
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Total funds
flow from
operations
(1) $ 177,563 $122,679 45 $ 468,255 $ 432,664 8
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Per weighted
average unit
- basic and
diluted (2) $ 0.72 $ 0.58 24 $ 2.04 $ 2.20 (7)
Distributions
to
unitholders $ 89,063 $ 75,573 18 $ 333,352 $ 283,465 18
Per unit $ 0.36 $ 0.36 - $ 1.44 $ 1.44 -
Percent of
funds flow
from
operations
paid
out as declared
distributions (3) 57% 64% (11) 77% 67% 15
Net income
(loss) (4) $ 68,545 $(25,501) - $ 30,434 $ 140,920 (78)
Per weighted
average unit
- basic and
diluted (2) $ 0.28 $ (0.12) - $ 0.13 $ 0.72 (82)
Capital
expenditures $ 93,365 $ 60,911 53 $ 247,122 $ 190,433 30
Capitol
Energy
acquisition $ (355)$ - - $ 467,495 $ - -
Triwest
Energy
acquisition $ 78,877 $ - - $ 78,877 $ - -
USOGP natural
gas asset
acquisition $1,464,213 $ - - $1,464,213 $ - -
Oil and gas
property
acquisitions,
net $ 2,788 $ 8,678 - $ 265,201 $ 481,625 -
Weighted
average trust
units
outstanding
(000s)
- Basic 247,052 209,826 18 229,939 196,627 17
- Diluted (2) 247,052 210,113 18 229,939 196,914 17
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Consolidated
----------------------------------------------------------------------------
As at December 31,
($ 000s) 2007 2006 % Change
----------------------------------------------------------------------------

Capitalization
Long-term debt $ 1,549,272 $ 988,785 57
Unitholders' equity $ 1,708,665 $ 1,542,974 11
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(1) Represents cash flow from operations before changes in working capital
and site restoration expenditures.
(2) Includes dilutive impact of unit options, exchangeable shares and
convertible debentures.
(3) Calculated as distributions to unitholders divided by funds flow from
operations less distributions to non-controlling interests of $35.8
million year-to-date and $22.1 million for the quarter (2006 - $6.5
million and $4.7 million, respectively).
(4) Net income (loss) for the year ended December 31, 2007 includes a future
income tax charge of $88.4 million relating to the enactment of Bill
C-52, Budget Implementation Act 2007 by the Canadian government.


Operational highlights

Three months ended Year ended
Consolidated December 31, December 31,
----------------------------------------------------------------------------
2007 2006 % Change 2007 2006 % Change
----------------------------------------------------------------------------
Oil and Gas
Production
Daily production
Light/medium crude
oil (bpd) 20,721 13,899 49 17,433 14,114 24
Heavy oil (bpd) 1,769 1,838 (4) 1,921 2,057 (7)
Natural gas
liquids (bpd) 1,612 1,345 20 1,421 1,419 -
Natural gas
(mcfpd) 144,678 100,029 45 107,151 84,891 26
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Oil equivalent
(boed)(1) 48,215 33,753 43 38,633 31,739 22
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Average realized
price (before
realized
financial
derivative
instruments)
Light/medium
crude oil
($/bbl) $ 69.70 $ 54.59 28 $ 63.48 $ 60.32 5
Heavy oil
($/bbl) $ 43.36 $ 25.82 68 $ 41.85 $ 36.80 14
Corporate oil
blend ($/bbl) $ 67.56 $ 51.23 32 $ 61.29 $ 57.33 7
Natural gas
liquids
($/bbl) $ 51.39 $ 47.49 8 $ 51.90 $ 51.98 -
Natural gas
($/mcf) $ 6.53 $ 6.71 (3) $ 6.53 $ 6.66 (2)
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Oil equivalent
($/boe)(1) $ 52.59 $ 45.65 15 $ 50.64 $ 49.35 3
----------------------------------------------------------------------------
Field netback
(before realized
financial
derivative
instruments)
($/boe) $ 30.22 $ 23.96 26 $ 28.24 $ 27.93 1
Field netback
(including
realized
financial
derivative
instruments)
($/boe) $ 28.31 $ 25.58 11 $ 27.79 $ 28.09 (1)
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Midstream
Midstream NGL
sales volumes
(bpd) 135,981 115,727 18 120,785 115,354 5
EBITDA (000s)
(2) $ 89,423 $ 74,422 20 $ 225,675 $ 219,631 3
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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".


Oil and Natural Gas Reserves

Provident's Canadian reserves were evaluated by McDaniel & Associates Consultants Ltd. (McDaniel) and by AJM Petroleum Consultants (AJM) effective December 31, 2007 in accordance with the Canadian Securities Administrators' National Instrument 51-101 Standards of Disclosure for Oil and Gas Activities (NI 51-101). Provident's United States reserves were evaluated by Netherland, Sewell & Associates, Inc. (NSAI) and by Schlumberger Data and Consulting Services (DCS) effective December 31, 2007 in accordance with NI 51-101. The Canadian and U.S evaluations used the McDaniel price forecast. McDaniel, AJM, NSAI and DCS 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.

To provide clarity, reserves and values are provided by country and on a consolidated basis. For consistency with Provident's financial reporting U.S. reserves are reported based on 100 percent of the interests of BreitBurn Energy Company L.P. (BreitBurn) and of BreitBurn Energy Partners L.P. (the "MLP") in the U.S. properties. As of December 31, 2007 Provident indirectly held approximately 96 percent of the outstanding partnership interests of BreitBurn with the remaining approximately four percent of the partnership interests held by BreitBurn's co-founders and co-chief executive officers. As of December 31, 2007 Provident indirectly held approximately 22 percent of the outstanding partnership interests of the MLP with the remaining approximately 78 percent of the partnership interests held by public unitholders and BreitBurn's co-founders and co-chief executive officers.

Provident Consolidated Oil and Natural Gas Reserves

Provident had a very successful year with respect to acquisitions and reserve additions in the drive to continually support the sustainability of the Trust. Acquisitions in Canada and in the U.S. improved the quality of the Trust's asset base, as evidenced by the increased reserve life index (RLI). Internal development activities in Western Canada, California and Wyoming were successful in replacing 57 percent of total production. The Trust's reserves increased after production with company interest proved producing reserves growing from 89,851 thousand barrels of oil equivalent1 (Mboe) to 206,063 Mboe, total proved growing from 117,806 Mboe to 253,272 Mboe, and proved plus probable growing from 153,021 Mboe to 322,827 Mboe.

Consolidated Oil and Natural Gas Reserves and Present Values

Provident's Consolidated oil and natural gas reserves and present value of estimated future cash flows based on forecast prices and costs using the McDaniel price forecast are summarized below. 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).



Provident Consolidated Reserves Summary(a)(b)
Using McDaniel Price Forecast
Gross 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 73,638 10,882 84,520 4,774 699,075 205,807
Non-Producing 4,247 1,547 5,794 432 60,065 16,236
Undeveloped 13,117 3,003 16,120 930 83,291 30,932
----------------------------------------------------------------------------
Total Proved 91,002 15,432 106,434 6,136 842,431 252,975
Probable 31,583 9,189 40,772 1,721 161,639 69,433
----------------------------------------------------------------------------
TOTAL Proved
plus Probable 122,585 24,621 147,206 7,857 1,004,069 322,408
----------------------------------------------------------------------------
----------------------------------------------------------------------------


Net Reserves(d)
----------------------------------------------------------------------------
Light &
Medium Heavy
Crude Crude Total Natural Total
Oil Oil Oil NGL Gas Boe
(Mbbl) (Mbbl) (Mbbl) (Mbbl) (MMcf) (Mboe)
----------------------------------------------------------------------------
Proved Reserves
Producing 64,520 9,819 74,339 3,854 579,689 174,808
Non-Producing 3,737 1,513 5,250 351 47,443 13,508
Undeveloped 11,138 2,867 14,005 775 69,030 26,285
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Total Proved 79,395 14,199 93,594 4,981 696,162 214,601
Probable 26,332 8,760 35,092 1,353 135,036 58,951
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TOTAL Proved
plus Probable 105,727 22,959 128,686 6,333 831,198 273,552
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----------------------------------------------------------------------------
(a) Tables may not add due to rounding.
(b) U.S. Reserves are reported based on 100% of the interests of BreitBurn
Energy Company L.P. (BreitBurn) and of BreitBurn Energy Partners L.P.
(the "MLP") in the U.S. properties. As of December 31, 2007 Provident
indirectly held approximately 96% of the outstanding partnership
interests of BreitBurn with the remaining approximately 4% of the
partnership interests held by BreitBurn's co-founders and co-chief
executive officers. As of December 31, 2007 Provident indirectly held
approximately 22% of the outstanding partnership interests of the MLP
with the remaining approximately 78% of the partnership interests held
by public unitholders and BreitBurn's co-founders and co-chief
executive officers. This is consistent with Provident's financial
reporting.
(c) Gross Reserves are Provident's working interest (operated or
non-operated) share before deduction of royalties and without including
any royalty interests of Provident.
(d) Net Reserves are Provident's working interest (operated or non-operated)
share after deduction of royalty obligations, plus Provident's royalty
interests in reserves.


Present Value of Consolidated Reserves

Present Value ($000's) Before Tax Discounted at
----------------------------------------------------------------------------
0% 8% 10%
----------------------------------------------------------------------------
Proved Reserves
Producing $ 6,251,207 $ 3,128,956 $ 2,818,145
Non-Producing $ 533,094 $ 275,968 $ 244,000
Undeveloped $ 881,581 $ 420,408 $ 364,282
----------------------------------------------------------------------------
Total Proved $ 7,665,882 $ 3,825,332 $ 3,426,427
Probable $ 2,386,511 $ 983,831 $ 835,162
----------------------------------------------------------------------------
TOTAL Proved plus Probable $ 10,052,393 $ 4,809,163 $ 4,261,590
----------------------------------------------------------------------------
----------------------------------------------------------------------------


Present Value ($000's) Before Tax Discounted at
----------------------------------------------------------------------------
15% 20%
----------------------------------------------------------------------------
Proved Reserves
Producing $ 2,292,954 $ 1,961,080
Non-Producing $ 187,078 $ 149,900
Undeveloped $ 263,844 $ 197,582
----------------------------------------------------------------------------
Total Proved $ 2,743,876 $ 2,308,562
Probable $ 587,853 $ 438,516
----------------------------------------------------------------------------
TOTAL Proved plus Probable $ 3,331,729 $ 2,747,078
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Present Value ($000's) After Tax(a) Discounted at
----------------------------------------------------------------------------
0% 8% 10%
----------------------------------------------------------------------------
Proved Reserves
Producing $ 6,114,740 $ 3,093,166 $ 2,789,489
Non-Producing 541,352 278,757 246,268
Undeveloped 817,687 398,130 346,030
----------------------------------------------------------------------------
Total Proved 7,473,779 3,770,053 3,381,787
Probable 2,146,124 925,739 792,717
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TOTAL Proved plus Probable $ 9,619,903 $ 4,695,792 $ 4,174,504
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Present Value ($000's) After Tax(a) Discounted at
----------------------------------------------------------------------------
15% 20%
----------------------------------------------------------------------------
Proved Reserves
Producing $ 2,274,097 $ 1,946,690
Non-Producing 188,536 150,930
Undeveloped 252,076 189,539
----------------------------------------------------------------------------
Total Proved 2,714,709 2,287,158
Probable 568,019 429,476
----------------------------------------------------------------------------
TOTAL Proved plus Probable $ 3,282,728 $ 2,716,634
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(a) After tax values include U.S. State and Federal Taxes as well as with
holding tax on funds that flow back to Provident Energy Ltd. in Canada
plus Canadian Federal and Provincial Income taxes beginning January 1,
2011.


COGP Oil and Natural Gas Reserves

McDaniel evaluated all of Provident's Canadian oil and natural gas reserves, except the Rainbow area assets of northwest Alberta which were evaluated by AJM. Drilling activity made a significant contribution with total proved plus probable drilling and recompletion additions replacing 44 percent of Canadian production. The acquisitions of Capitol Energy Resources Ltd. (Capitol) and Triwest Energy Inc. (Triwest) plus various smaller acquisitions added proved plus probable reserves of 33,292 Mboe. To comply with NI 51-101 requirements that acquisitions be reported as evaluated at the time of the year-end filing the 2007 acquisitions are reported herein as per the McDaniel December 31, 2007 evaluation with actual production added back to develop the actual volumes acquired at the time of acquisition.

Over 90 percent of the value of the assets acquired from Capitol is associated with the Dixonville Montney "C" pool in northwest Alberta. This well-delineated homogeneous pool, which produces 30 degree API oil, is being developed using horizontal wells and waterflood technology. All of the production is 100 percent working interest and is operated by Provident. The assets acquired from Triwest are located principally in the Steelman, Crystal Hills and Ingoldsby areas in southeast Saskatchewan. These properties, which produce light crude oil, are also developed using horizontal well technology.

Revisions, excluding economic factors, accounted for a five percent increase in proved developed producing (PDP) reserves and a two percent increase in total proved reserves. The positive revisions are an indication of the high degree of confidence in Provident's Canadian reserves. Provident's percentage of PDP reserves has decreased from 62 percent to 51 percent of total proved plus probable reserves since December 2006 due to the acquisition of undeveloped reserves from Capitol, primarily at Dixonville, Alberta and from Triwest in southeast Saskatchewan. Changes in commodity prices had no significant impact on Canadian reserve volumes. After accounting for production of 9,676 Mboe, acquisitions, divestitures, additions and revisions resulted in a 37 percent increase in company share proved plus probable reserves from 74,137 Mboe on December 31, 2006 to 101,239 Mboe (100,820 Mboe WI share) at December 31, 2007.

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

In October 2007, the Alberta government announced its intention to increase crown royalties effective January 1, 2009. As of December 31, 2007, legislation enabling the Alberta new royalty framework had not been passed. Furthermore, the government had not provided sufficient clarity on a number of issues to allow precise calculation of net reserves and net present value under the new proposed royalties. Therefore, COGP reserves as presented herein are based on the existing royalty regime. High and low sensitivities, which were run to determine the potential impact of the proposed new royalty framework, indicate no impact on company interest reserves but a potential eight to ten percent decrease in before tax net present value (discounted at 10%) of COGP proved plus probable reserves. Details of reserves and values for these sensitivities are provided in Form NI 51-101 F1.



COGP Reserves Summary(a)
Using McDaniel Price Forecast
Gross Reserves(b)
----------------------------------------------------------------------------
Light & Heavy
Medium Crude Total Natural Total
Crude Oil Oil Oil NGL Gas Boe
(Mbbl) (Mbbl) (Mbbl) (Mbbl) (MMcf) (Mboe)
----------------------------------------------------------------------------
Reserves
Producing 19,015 1,142 20,157 2,222 172,128 51,067
Non-Producing 895 273 1,168 48 15,613 3,818
Undeveloped 5,520 423 5,943 114 21,791 9,689
----------------------------------------------------------------------------
Total Proved 25,429 1,838 27,267 2,384 209,532 64,573
Probable 19,932 1,885 21,817 880 81,299 36,247
----------------------------------------------------------------------------
TOTAL Proved
plus Probable 45,361 3,723 49,084 3,264 290,832 100,820
----------------------------------------------------------------------------
----------------------------------------------------------------------------

Net Reserves(c)
----------------------------------------------------------------------------
Light & Heavy
Medium Crude Total Natural Total
Crude Oil Oil Oil NGL Gas Boe
(Mbbl) (Mbbl) (Mbbl) (Mbbl) (MMcf) (Mboe)
----------------------------------------------------------------------------
Reserves
Producing 16,167 966 17,133 1,646 145,207 42,980
Non-Producing 781 239 1,020 38 12,020 3,061
Undeveloped 4,750 361 5,111 75 17,990 8,184
----------------------------------------------------------------------------
Total Proved 21,697 1,566 23,264 1,759 175,216 54,225
Probable 16,506 1,641 18,147 646 69,163 30,321
----------------------------------------------------------------------------
TOTAL Proved
plus Probable 38,204 3,207 41,411 2,405 244,379 84,545
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(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.


Present Value of COGP Reserves (a)(b)

Present Worth Value ($000's) Before Tax Discounted at
----------------------------------------------------------------------------
0% 8% 10% 15% 20%
----------------------------------------------------------------------------
Proved Reserves
Producing $1,367,465 $1,032,120 $ 975,009 $ 860,619 $ 774,765
Non-Producing 73,575 62,671 57,748 47,762 40,610
Undeveloped 214,065 118,607 103,567 74,491 53,742
----------------------------------------------------------------------------
Total Proved 1,655,105 1,213,398 1,136,324 982,872 869,117
Probable 1,258,344 511,244 437,219 315,866 243,146
----------------------------------------------------------------------------
TOTAL Proved
plus Probable $2,913,449 $1,724,642 $1,573,543 $1,298,738 $1,112,263
----------------------------------------------------------------------------
----------------------------------------------------------------------------

Present Value ($000's) After Tax(b) Discounted at
----------------------------------------------------------------------------
0% 8% 10% 15% 20%
----------------------------------------------------------------------------
Proved Reserves
Producing $1,367,465 $1,032,120 $ 975,009 $ 860,619 $ 774,765
Non-Producing 73,575 62,671 57,748 47,762 40,610
Undeveloped 214,065 118,607 103,567 74,491 53,742
----------------------------------------------------------------------------
Total Proved 1,655,105 1,213,398 1,136,324 982,872 869,117
Probable 1,061,182 457,888 396,459 293,738 230,313
----------------------------------------------------------------------------
TOTAL Proved
plus Probable $2,716,287 $1,671,286 $1,532,783 $1,276,610 $1,099,430
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(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.


USOGP Oil and Natural Gas Reserves

Provident's U. S. oil and natural gas reserves were evaluated by Netherland, Sewell and Associates, Inc. (NSAI) and by Schlumberger Data and Consulting Services (DCS) effective December 31, 2007 in accordance with NI 51-101. Michigan, Indiana and Kentucky properties that were acquired by BreitBurn Energy Partners L.P. were evaluated by DCS while the remaining properties were evaluated by NSAI. The U.S evaluations used the McDaniel price forecast. NSAI and DCS are qualified reserve evaluators in accordance with NI 51-101.

Provident's USOGP division had a very successful year with respect to acquisitions. BreitBurn closed four major and two small acquisitions during the year thereby increasing proved plus probable reserves by 148,858 Mboe. The most significant was the acquisition of Michigan, Indiana and Kentucky assets with over 5,000 gross wells which produce gas from the Antrim and New Albany shales and oil and gas from conventional reservoirs. BreitBurn acquired oil producing assets in the Sunniland Trend in southern Florida and oil and gas producing assets in the Texas Permian Basin. BreitBurn also increased its working interests in the Sawtelle and East Coyote fields in California and several other oil fields in California and Wyoming.

Drilling activity in California and Wyoming added proved plus probable reserves of 3,731 Mboe, replacing 84 percent of U.S. production. These additions include reserves added as a result of continuing heavy oil development at the Orcutt Hill field in the Santa Maria Basin of California where steam injection and production have commenced. The North Sunshine field in Wyoming was discovered in 1928 but BreitBurn set a new production record in May 2007.

Technical revisions accounted for a seven percent decrease in proved plus probable reserves. These revisions are primarily associated with undeveloped drilling and waterflood reserves in the Los Angeles basin. After accounting for production of 4,425 Mboe and these revisions, acquisitions and additions resulted in the significant growth of company share proved plus probable reserves from 78,885 Mboe as of December 31, 2006 to 221,589 Mboe as of December 31, 2007.

USOGP oil and natural gas reserves and present value of estimated future cash flows based on forecast prices and costs are summarized below.



USOGP Reserves Summary(a)(b)
Using McDaniel Price Forecast

Gross Reserves
----------------------------------------------------------------------------
Light & Heavy
Medium Crude Total Natural Total
Crude Oil Oil Oil NGL Gas Boe
(Mbbl) (Mbbl) (Mbbl) (Mbbl) (MMcf) (Mboe)
----------------------------------------------------------------------------
Proved Reserves
Producing 54,624 9,740 64,364 2,552 526,947 154,741
Non-Producing 3,352 1,274 4,626 384 44,451 12,419
Undeveloped 7,597 2,580 10,178 816 61,500 21,243
----------------------------------------------------------------------------
Total Proved 65,573 13,594 79,167 3,753 632,898 188,402
Probable 11,651 7,304 18,955 841 80,340 33,186
----------------------------------------------------------------------------
TOTAL Proved
plus Probable 77,224 20,898 98,122 4,593 713,238 221,589
----------------------------------------------------------------------------
----------------------------------------------------------------------------

Net Reserves
----------------------------------------------------------------------------
Light & Heavy
Medium Crude Total Natural Total
Crude Oil Oil Oil NGL Gas Boe
(Mbbl) (Mbbl) (Mbbl) (Mbbl) (MMcf) (Mboe)
----------------------------------------------------------------------------
Proved Reserves
Producing 48,353 8,853 57,207 2,209 434,482 131,829
Non-Producing 2,956 1,274 4,230 314 35,423 10,447
Undeveloped 6,388 2,505 8,894 700 51,041 18,100
----------------------------------------------------------------------------
Total Proved 57,698 12,632 70,330 3,222 520,946 160,376
Probable 9,826 7,119 16,945 707 65,873 28,630
----------------------------------------------------------------------------
TOTAL Proved
plus Probable 67,523 19,752 87,275 3,929 586,819 189,007
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(a) Tables may not add due to rounding.
(b) U.S. Reserves are reported based on 100% of the interests of BreitBurn
Energy Company L.P. (BreitBurn) and of BreitBurn Energy Partners L.P.
(the "MLP") in the U.S. properties. As of December 31, 2007 Provident
indirectly held approximately 96% of the outstanding partnership
interests of BreitBurn with the remaining approximately 4% of the
partnership interests held by BreitBurn's co-founders and co-chief
executive officers. As of December 31, 2007 Provident indirectly held
approximately 22% of the outstanding partnership interests of the MLP
with the remaining approximately 78% of the partnership interests held
by public unitholders and BreitBurn's co-founders and co-chief executive
officers. This is consistent with Provident's financial reporting.


Present Value of USOGP Reserves (a)(b)

Present Value ($000's) Before Tax Discounted at
----------------------------------------------------------------------------
0% 8% 10% 15% 20%
----------------------------------------------------------------------------
Proved Reserves
Producing $4,883,742 $2,096,836 $1,843,136 $1,432,335 $1,186,315
Non-Producing 459,519 213,297 186,251 139,316 109,290
Undeveloped 667,516 301,801 260,716 189,353 143,840
----------------------------------------------------------------------------
Total Proved 6,010,777 2,611,934 2,290,103 1,761,004 1,439,445
Probable 1,128,167 472,587 397,944 271,987 195,370
----------------------------------------------------------------------------
TOTAL Proved
plus Probable $7,138,944 $3,084,521 $2,688,047 $2,032,991 $1,634,815
----------------------------------------------------------------------------
----------------------------------------------------------------------------

Present Value ($000's) After Tax(c) Discounted at
----------------------------------------------------------------------------
0% 8% 10% 15% 20%
----------------------------------------------------------------------------
Proved Reserves
Producing $4,747,275 $2,061,046 $1,814,480 $1,413,479 $1,171,925
Non-Producing 467,777 216,086 188,519 140,774 110,320
Undeveloped 603,622 279,523 242,464 177,585 135,797
----------------------------------------------------------------------------
Total Proved 5,818,674 2,556,655 2,245,463 1,731,837 1,418,041
Probable 1,084,942 467,851 396,258 274,281 199,163
----------------------------------------------------------------------------
TOTAL Proved
plus Probable $6,903,616 $3,024,506 $2,641,720 $2,006,118 $1,617,204
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(a) Tables may not add due to rounding
(b) Values in Canadian dollars
(c) After tax values include U.S. State and Federal Taxes as well as with
holding tax on funds that flow back to Provident Energy Ltd. in Canada.


USOGP Proportionate Information

For consistency with Provident's financial reporting U.S. reserves are reported based on 100 percent of the interests of BreitBurn Energy Company L.P. (BreitBurn) and of BreitBurn Energy Partners L.P. (the "MLP") in the U.S. properties. As of December 31, 2007 Provident held approximately 96% of BreitBurn and approximately 4% of the MLP. The following tables provide the proportionate information on the reserves and value of USOGP.



USOGP Reserves and Value Proportionate Information(a)(b)
Using McDaniel Price Forecast

Gross Reserves
---------------------------------------------
Light &
Medium Heavy Natural Total
Oil Oil NGL Gas Boe
(Mbbl) (Mbbl) (Mbbl) (MMcf) (Mboe)
---------------------------------------------
MLP
-------------------------------
Proved
Producing 40,057 7,608 2,522 523,327 137,408
Non-Producing 3,094 0 384 44,451 10,887
Undeveloped 5,430 646 734 58,289 16,525
----------------------------------------------------------------------------
Total Proved 48,581 8,254 3,641 626,068 164,820
Probable 4,150 1,631 532 70,400 18,046
----------------------------------------------------------------------------
TOTAL Proved
plus Probable 52,731 9,884 4,173 696,468 182,866
----------------------------------------------------------------------------
----------------------------------------------------------------------------

Provident's Interest of MLP(a)
-------------------------------
Proved
Producing 8,812 1,674 555 115,132 30,230
Non-Producing 681 0 85 9,779 2,395
Undeveloped 1,195 142 162 12,824 3,635
----------------------------------------------------------------------------
Total Proved 10,688 1,816 801 137,735 36,260
Probable 913 359 117 15,488 3,970
----------------------------------------------------------------------------
TOTAL Proved
plus Probable 11,601 2,175 918 153,223 40,231
----------------------------------------------------------------------------
----------------------------------------------------------------------------

BreitBurn
-------------------------------
Proved
Producing 14,567 2,132 30 3,620 17,332
Non-Producing 258 1,274 0 0 1,532
Undeveloped 2,167 1,935 82 3,211 4,718
----------------------------------------------------------------------------
Total Proved 16,992 5,341 112 6,831 23,583
Probable 7,501 5,674 309 9,940 15,140
----------------------------------------------------------------------------
TOTAL Proved
plus Probable 24,493 11,014 421 16,770 38,722
----------------------------------------------------------------------------
----------------------------------------------------------------------------

Provident's Interest of
BreitBurn(b)
-------------------------------
Proved
Producing 13,984 2,047 29 3,475 16,639
Non-Producing 248 1,223 0 0 1,471
Undeveloped 2,080 1,857 78 3,082 4,530
----------------------------------------------------------------------------
Total Proved 16,312 5,127 107 6,557 22,639
Probable 7,201 5,447 297 9,542 14,534
----------------------------------------------------------------------------
TOTAL Proved
plus Probable 23,513 10,574 404 16,099 37,173
----------------------------------------------------------------------------
----------------------------------------------------------------------------

Provident's Interest of USOGP
-------------------------------
Proved
Producing 22,797 3,721 584 118,607 46,869
Non-Producing 929 1,223 85 9,779 3,866
Undeveloped 3,275 1,999 240 15,906 8,165
----------------------------------------------------------------------------
Total Proved 27,000 6,943 908 144,292 58,900
Probable 8,114 5,805 414 25,030 18,504
----------------------------------------------------------------------------
TOTAL Proved
plus Probable 35,114 12,748 1,322 169,322 77,404
----------------------------------------------------------------------------
----------------------------------------------------------------------------

Present Value ($000's) Before Tax Discounted at
-----------------------------------------------------------
0% 8% 10% 15% 20%
-----------------------------------------------------------
MLP
-----------------
Proved
Producing 4,454,324 1,872,302 1,643,794 1,276,330 1,057,417
Non-Producing 414,479 183,010 158,378 116,154 89,520
Undeveloped 559,411 242,041 208,209 150,382 114,045
----------------------------------------------------------------------------
Total Proved 5,428,215 2,297,354 2,010,380 1,542,866 1,260,982
Probable 637,428 256,203 216,914 151,440 111,688
----------------------------------------------------------------------------
TOTAL Proved
plus Probable 6,065,643 2,553,556 2,227,294 1,694,306 1,372,670
----------------------------------------------------------------------------
----------------------------------------------------------------------------

Provident's
Interest of
MLP(a)
-----------------
Proved
Producing 979,951 411,906 361,635 280,793 232,632
Non-Producing 91,185 40,262 34,843 25,554 19,694
Undeveloped 123,071 53,249 45,806 33,084 25,090
----------------------------------------------------------------------------
Total Proved 1,194,207 505,418 442,284 339,430 277,416
Probable 140,234 56,365 47,721 33,317 24,571
----------------------------------------------------------------------------
TOTAL Proved
plus Probable 1,334,441 561,782 490,005 372,747 301,987
----------------------------------------------------------------------------
----------------------------------------------------------------------------

BreitBurn
-----------------
Proved
Producing 429,418 224,534 199,343 156,005 128,899
Non-Producing 45,040 30,287 27,874 23,162 19,770
Undeveloped 108,104 59,760 52,507 38,971 29,795
----------------------------------------------------------------------------
Total Proved 582,562 314,580 279,723 218,138 178,463
Probable 490,739 216,385 181,030 120,547 83,682
----------------------------------------------------------------------------
TOTAL Proved
plus Probable 1,073,302 530,965 460,754 338,685 262,145
----------------------------------------------------------------------------
----------------------------------------------------------------------------

Provident's
Interest of
BreitBurn(b)
-----------------
Proved
Producing 412,241 215,553 191,369 149,765 123,743
Non-Producing 43,238 29,075 26,759 22,236 18,979
Undeveloped 103,780 57,369 50,407 37,412 28,603
----------------------------------------------------------------------------
Total Proved 559,260 301,997 268,534 209,412 171,325
Probable 471,110 207,729 173,789 115,725 80,334
----------------------------------------------------------------------------
TOTAL Proved
plus Probable 1,030,369 509,726 442,323 325,138 251,659
----------------------------------------------------------------------------
----------------------------------------------------------------------------

Provident's
Interest of
USOGP
-----------------
Proved
Producing 1,392,193 627,459 553,004 430,557 356,374
Non-Producing 134,424 69,338 61,602 47,790 38,674
Undeveloped 226,850 110,618 96,213 70,496 53,693
----------------------------------------------------------------------------
Total Proved 1,753,467 807,415 710,818 548,843 448,741
Probable 611,344 264,094 221,510 149,042 104,906
----------------------------------------------------------------------------
TOTAL Proved
plus Probable 2,364,811 1,071,509 932,328 697,885 553,647
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(a) Provident interest in MLP = 22%
(b) Provident interest in BreitBurn = 96%


Consolidated Proportionate Information

Provident's interest share of total United States and Canada reserves and
value as of December 31, 2007 is shown in the following table.

United States and Canada Reserves and Value
Provident Interest using McDaniel Price Forecast

Gross Reserves
---------------------------------------------
Light &
Medium Heavy Natural Total
Oil Oil NGL Gas Boe
Proved (Mbbl) (Mbbl) (Mbbl) (MMcf) (Mboe)
---------------------------------------------
Producing 41,812 4,862 2,806 290,735 97,936
Non-Producing 1,823 1,496 132 25,392 7,683
Undeveloped 8,795 2,422 354 37,697 17,854
----------------------------------------------------------------------------
Total Proved 52,429 8,781 3,292 353,825 123,472
Probable 28,046 7,690 1,294 106,329 54,751
----------------------------------------------------------------------------
TOTAL Proved
plus Probable 80,475 16,471 4,585 460,154 178,224
----------------------------------------------------------------------------
----------------------------------------------------------------------------

Present Value ($000's) Before Tax Discounted at
-----------------------------------------------------------
Proved 0% 8% 10% 15% 20%
Producing 2,759,658 1,659,579 1,528,013 1,291,176 1,131,139
Non-Producing 207,998 132,009 119,350 95,552 79,283
Undeveloped 440,915 229,225 199,779 144,987 107,435
----------------------------------------------------------------------------
Total Proved 3,408,571 2,020,813 1,847,142 1,531,715 1,317,857
Probable 1,869,688 775,338 658,729 464,908 348,052
----------------------------------------------------------------------------
TOTAL Proved
plus Probable 5,278,260 2,796,151 2,505,871 1,996,623 1,665,909
----------------------------------------------------------------------------
----------------------------------------------------------------------------


Provident Consolidated Reconciliation Summaries

The following reconciliation tables summarize Provident's consolidated reserve activity for each reserve category for the year ended December 31, 2007 on the basis of company share reserves. Working interest reserves as of December 31, 2007 are provided at the bottom of each table to tie back to the volumes provided in the previous tables.



Provident Consolidated Reconciliation Summary (d)
Proved Developed Producing

Light &
Medium Heavy Total
Company Share Crude Crude Crude
(WI+RI)(a)(c) Oil Oil Oil Gas NGL Total
Mbbl Mbbl Mbbl MMcf Mbbl Mboe
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Balance at
December 31, 2006 49,133 6,738 55,871 188,738 2,524 89,851
Production (6,068) (996) (7,064) (39,110) (518) (14,101)
Drilling Activity
Exploration Discoveries 132 0 132 0 0 132
Drilling Extensions 491 0 491 6,663 34 1,635
Recompletion 149 693 843 2,504 17 1,277
Transfer 1,808 0 1,808 4,113 15 2,509
Acquisition 26,510 3,802 30,311 533,180 2,573 121,748
Divestiture (22) 0 (22) (146) (1) (47)
Economic Factors 733 369 1,102 (1,439) (0) 862
Technical Revisions 805 284 1,090 5,710 156 2,197
----------------------------------------------------------------------------
Balance at
December 31, 2007 73,671 10,890 84,562 700,214 4,800 206,063
----------------------------------------------------------------------------
----------------------------------------------------------------------------
WI Share (b)
Balance at
December 31, 2007 73,638 10,882 84,520 699,075 4,774 205,807
----------------------------------------------------------------------------
----------------------------------------------------------------------------

Provident Consolidated Reconciliation Summary (d)
Total Proved

Light &
Medium Heavy Total
Company Share Crude Crude Crude
(WI +RI) (a)(c) Oil Oil Oil Gas NGL Total
Mbbl Mbbl Mbbl MMcf Mbbl Mboe
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Balance at
December 31, 2006 63,076 11,958 75,034 236,464 3,362 117,806
Production (6,068) (996) (7,064) (39,110) (518) (14,101)
Drilling Activity
Exploration Discoveries 132 0 132 0 0 132
Drilling Extensions 1,901 0 1,901 9,923 40 3,595
Recompletion 169 734 903 2,492 18 1,337
Transfer 981 0 981 1,900 6 1,303
Acquisition 36,547 3,802 40,349 641,842 3,692 151,015
Divestiture (22) 0 (22) (146) (1) (47)
Economic Factors 929 339 1,268 (1,318) 8 1,056
Technical Revisions (6,611) (396) (7,007) (8,270) (440) (8,825)
----------------------------------------------------------------------------
Balance at
December 31, 2007 91,035 15,440 106,475 843,776 6,167 253,272
----------------------------------------------------------------------------
----------------------------------------------------------------------------
WI Share (b)
Balance at
December 31, 2007 91,002 15,432 106,434 842,431 6,136 252,975
----------------------------------------------------------------------------
----------------------------------------------------------------------------

Provident Consolidated Reconciliation Summary (d)
Total Proved plus Probable

Light &
Medium Heavy Total
Company Share Crude Crude Crude
(WI +RI) (a)(c) Oil Oil Oil Gas NGL Total
Mbbl Mbbl Mbbl MMcf Mbbl Mboe
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Balance at
December 31, 2006 74,824 19,238 94,062 325,665 4,681 153,021
Production (6,068) (996) (7,064) (39,110) (518) (14,101)
Drilling Activity
Exploration
Discoveries 132 0 132 0 0 132
Drilling Extensions 3,778 0 3,778 14,531 56 6,256
Recompletion 209 887 1,096 3,125 23 1,640
Transfer 0 0 0 0 0 0
Acquisition 54,697 4,100 58,797 714,745 4,229 182,150
Divestiture (28) 0 (28) (261) (1) (73)
Economic Factors 283 383 666 (3,198) 2 135
Technical Revisions (5,196) 1,020 (4,177) (9,496) (573) (6,333)
----------------------------------------------------------------------------
Balance at
December 31, 2007 122,630 24,632 147,262 1,006,000 7,898 322,826
----------------------------------------------------------------------------
----------------------------------------------------------------------------
WI Share (b)
Balance at
December 31, 2007 122,585 24,621 147,206 1,004,069 7,857 322,408
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(a) Company share includes working interest (WI) and royalty interest (RI)
volumes.
(b) WI share includes the Company's working interests only, and excludes
volumes associated with royalties.
(c) Tables may not add due to rounding.
(d) U.S. Reserves are reported based on 100% of the interests of BreitBurn
Energy Company L.P. (BreitBurn) and of BreitBurn Energy Partners L.P.
(the "MLP") in the U.S. properties. As of December 31, 2007 Provident
indirectly held approximately 96% of the outstanding partnership
interests of BreitBurn with the remaining approximately 4% of the
partnership interests held by BreitBurn's co-founders and co-chief
executive officers. As of December 31, 2007 Provident indirectly held
approximately 22% of the outstanding partnership interests of the MLP
with the remaining approximately 78% of the partnership interests held
by public unitholders and BreitBurn's co-founders and co-chief executive
officers. This is consistent with Provident's financial reporting.


Price Forecast Summary

The following table summarizes the McDaniel January 1, 2008 price forecast used in evaluating Provident's reserves under forecast price and cost assumptions.



WTI Light,
Crude at Sweet Heavy Alberta
Cushing Crude at Oil at AECO Gas
Exchange Rate Oklahoma Edmonton Hardisty Spot Price
Year US$/Cdn$ US$/bbl Cdn$/bbl Cdn$/bbl Cdn$/MMbtu(a)
----------------------------------------------------------------------------
2008 1.000 90.00 89.00 55.30 6.80
2009 1.000 86.70 85.70 53.20 7.38
2010 1.000 83.20 82.20 50.50 7.38
2011 1.000 79.60 78.50 48.70 7.38
2012 1.000 78.50 77.40 48.00 7.49
----------------------------------------------------------------------------
----------------------------------------------------------------------------

(a) Alberta AECO Gas Spot price assuming 1,000 btu/scf


Reserve Life Index (RLI)

The acquisition of the Dixonville and southeast Saskatchewan assets increased the Trust's Reserve Life Index (RLI) in 2007. Provident's RLI of 16.9 years as of December 31, 2007 was determined by applying the average actual production rates for December 2007 to COGP and USOGP reserve volumes for each reserve category from the McDaniel, AJM, NSAI and DCS evaluations as of December 31, 2007.

The following tables illustrate the reserve life index for Provident for the various product and reserve categories and the RLI by country as of December 31, 2007.



Provident Consolidated Reserve Life Index
Company share (WI + RI)
December 31
Total Crude Oil 2007 2006 2005 2004 2003
----------------------------------------------------------------------------
Proved Producing 9.8 9.7 8.2 6.5 3.0
Total Proved 12.4 13.1 11.7 8.9 3.9
Proved plus Probable 17.1 16.4 14.9 11.7 5.4

Natural Gas & NGL
----------------------------------------------------------------------------
Proved Producing 11.6 5.2 4.5 4.2 4.4
Total Proved 14.0 6.5 6.0 5.5 4.9
Proved plus Probable 16.7 9.0 7.9 7.2 6.1

Oil Equivalent (6:1)
----------------------------------------------------------------------------
Proved Producing 10.8 7.3 6.6 5.5 3.7
Total Proved 13.3 9.6 9.2 7.4 4.4
Proved plus Probable 16.9 12.4 11.8 9.7 5.7



Canada and United States Reserve Life Index Company share (WI + RI)

December 31, 2007
Total Crude Oil COGP USOGP
----------------------------------------------------------------------------
Proved Producing 4.6 15.2
Total Proved 6.2 18.7
Proved plus Probable 11.2 23.2

Natural Gas & NGL
----------------------------------------------------------------------------
Proved Producing 5.2 20.0
Total Proved 6.3 24.2
Proved plus Probable 8.7 27.3

Oil Equivalent (6:1)
----------------------------------------------------------------------------
Proved Producing 4.9 17.7
Total Proved 6.2 21.6
Proved plus Probable 9.7 25.4


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. 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 2007 made a significant contribution with total proved additions of 5,064 Mboe and proved plus probable additions of 8,027 Mboe. As an energy trust and not an exploration oriented venture, Provident's focus is development and exploitation of reserves and promotes between reserve categories. As a result of capital expenditures during 2007, Provident promoted 2,509 Mboe of reserves into the proved developed producing category. The associated capital and any changes to it have been accounted for in the F&D calculations. Provident's all-in finding, development and acquisition costs for 2007 were $15.18/boe.

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.

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. Three-year average total proved and probable FD&A costs are $16.05 per boe, including reserve revisions and changes in FDC.

The following table presents the details of the 2007 Finding, Development and Acquisition cost calculation for Provident and illustrates the impact of including the change in future development capital in the calculation.



Provident Consolidated
2007 Finding, Development and Acquisition Costs (FD&A)

Company
Interest
Capital Reserve Reserves
Expenditures Additions (3) Costs
---------------------------------------
($000s) Mboe(4) $/boe(4)
Total Proved
Total FD&A Costs (1) (a) $ 2,498,730 149,566 $ 16.71
Change in FDC(2) (b) 185,856
------------
------------
Total FD&A including change in
FDC (a+b) $ 2,684,587 149,566 $ 17.95

Proved + Probable
Total FD&A Costs (1) (a) $ 2,498,730 183,906 $ 13.59
Change in FDC(2) (b) 292,542
------------
------------
Total FD&A including change in
FDC (a+b) $ 2,791,273 183,906 $ 15.18
----------------------------------------------------------------------------

Notes:
(1) Total FD&A Costs ($000s)
2007 Oil and Gas Capital
Expenditures $ 148,464
Property Acquisitions (net
dispositions) $ 1,754,023
Corporate Acquisitions $ 596,243
------------
------------
Total Oil and Gas FD&A costs $ 2,498,730
----------------------------------------------------------------------------
(2) Change in Future Development Costs
($000s) Proved
Total plus
Proved Probable
--------------------------
--------------------------
FDC as of December 31, 2007 $ 335,387 $ 547,189
FDC as of December 31, 2006 $ 149,531 $ 254,647
--------------------------
--------------------------
Change in FDC $ 185,856 $ 292,542

----------------------------------------------------------------------------
----------------------------------------------------------------------------
(3) Reserve Additions include revisions.

(4) 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. BOE conversions of 1:1
were used for Heavy Oil and NGL.


The following tables present finding and development costs and finding, development and acquisition costs for proved and proved plus probable reserves on a consolidated basis and by country.



Provident Consolidated Finding and Development Costs $ per boe)

Three year
2007 2006 2005 average (d)
----------------------------------------------------------------------------
Finding and Development Costs per boe
(includes FDC) (a)(b)(c)
Proved
Additions $ 22.02 $ 26.84 $ 23.79 $ 23.88
Additions including revisions - (e) $ 13.68 $ 22.90 $ 30.76
Proved plus probable
Additions $ 19.82 $ 17.21 $ 16.37 $ 17.80
Additions including revisions - (e) $ 19.04 $ 28.39 $ 31.89

Finding, Development and Acquisition
Costs per boe (includes FDC)
Proved
Proved excluding revisions $ 17.06 $ 29.92 $ 12.03 $ 18.05
Proved including revisions $ 17.95 $ 25.18 $ 11.88 $ 18.38
Proved plus probable
Proved plus probable
excluding revisions $ 14.68 $ 21.56 $ 11.73 $ 15.35
Proved plus probable
including revisions $ 15.18 $ 22.04 $ 14.44 $ 16.05
----------------------------------------------------------------------------


COGP Finding and Development Costs ($ per boe)
Three year
2007 2006 2005 average (d)
----------------------------------------------------------------------------

Finding and Development Costs per boe
(includes FDC) (a)(b)(c)
Proved
Additions $ 25.55 $ 24.76 $ 17.61 $ 22.20
Additions including
revisions $ 20.39 $ 25.06 $ 15.35 $ 19.36
Proved plus probable
Additions $ 20.23 $ 16.80 $ 11.61 $ 16.05
Additions including
revisions $ 24.42 $ 23.99 $ 15.01 $ 20.82

Finding, Development and Acquisition Costs
per boe (includes FDC)
Proved
Proved excluding revisions $ 41.48 $ 30.07 - (e) $ 36.57
Proved including revisions $ 39.76 $ 30.11 - (e) $ 35.31
Proved plus probable
Proved plus probable
excluding revisions $ 22.85 $ 22.12 - (e) $ 23.36
Proved plus probable
including revisions $ 23.31 $ 23.04 - (e) $ 24.48
----------------------------------------------------------------------------


USOGP Finding and Development Costs (Canadian $ per boe)

Three year
2007 2006 2005 average (d)
----------------------------------------------------------------------------
Finding and Development Costs per boe
(includes FDC) (a)(b)(c)
Proved
Additions $ 17.81 $ 29.46 - (e) $ 26.48
Additions including
revisions - (e)$ 9.24 - (e) - (e)
Proved plus probable
Additions $ 19.35 $ 17.65 $ 22.32 $ 19.81
Additions including
revisions - (e)$ 15.80 - (e) - (e)

Finding, Development and Acquisition Costs per boe
(includes FDC)
Proved
Proved excluding
revisions $ 13.45 $ 28.38 $ 10.57 $ 13.32
Proved including
revisions $ 14.35 $ 8.90 $ 10.80 $ 13.76
Proved plus probable
Proved plus probable
excluding revisions $ 12.67 $ 17.08 $ 10.20 $ 12.47
Proved plus probable
including revisions $ 13.14 $ 15.29 $ 11.59 $ 13.03
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(a) FDC - Future Development Capital, excluding USOGP Obligatory
(Maintenance) capital.
(b) Based on Company share reserves.
(c) 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.
(d) Three-year average is the average of 2005, 2006 and 2007. 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.
(e) Revisions exceed additions or dispositions exceed acquisitions plus
additions, therefore the calculation is not included in the table.


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.

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

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

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

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

Fourth quarter highlights

The fourth quarter highlights section provides commentary on the fourth quarter 2007 results compared to the fourth quarter of 2006. 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) 2007 2006 % Change
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Revenue, Funds Flow from Operations
and Distributions
Revenue (net of royalties and
financial derivative instruments) $ 541,884 $ 548,086 (1)
----------------------------------------------------------------------------
Funds flow from operations $ 177,563 $ 122,679 45
Per weighted average unit -
basic and diluted (1) $ 0.72 $ 0.58 24
----------------------------------------------------------------------------
Declared distributions $ 89,063 $ 75,573 18
Per Unit 0.36 0.36 -
Percent of funds flow from
operations distributed (2) 57% 64% (11)
----------------------------------------------------------------------------
(1) Includes dilutive impact of unit options, exchangeable shares and
convertible debentures.
(2) Calculated as declared distributions to unitholders divided by funds
flow from operations less distributions to non-controlling interests of
$22.1 million for the quarter (2006 - $4.7 million).


Fourth quarter 2007 funds flow from operations was $177.6 million, 45 percent above the $122.7 million recorded in the fourth quarter of 2006. COGP 2007 fourth quarter funds flow from operations was $58.7 million, a 21 percent increase from the $48.6 million recorded in the comparable 2006 quarter. The main drivers for the COGP increase were increased production primarily from the acquisitions of Capitol Resources Ltd. ("Capitol") on June 19, 2007 and Triwest Energy Inc. ("Triwest") on December 3, 2007, which were primarily light/medium crude oil production. Higher realized crude oil and natural gas liquids prices also positively contributed to the increase in COGP funds flow from operations. The increase was partially offset by lower realized natural gas price due to the decrease in the AECO natural gas index price. The Midstream business unit added $77.1 million to fourth quarter 2007 funds flow from operations, 27 percent above the $60.5 million recorded in the comparable 2006 quarter. This increase reflects higher operating margins for all business lines within the Midstream segment, partially offset by realized losses on financial derivative instruments. Funds flow from operations in USOGP increased 208 percent to $41.8 million compared to $13.6 million in the comparable 2006 quarter. The increase is primarily driven by increased production due to oil and gas property acquisitions by the MLP in 2007, including the $1.5 billion USOGP natural gas asset acquisition in November 2007, combined with higher commodity prices.

Declared distributions in the fourth quarter of 2007 totaled $89.1 million, 57 percent of funds flow from operations, after distributions to non-controlling interests of $22.1 million. This compares to $75.6 million of declared distributions in fourth quarter 2006, 64 percent of funds flow from operations, after distributions to non-controlling interests of $4.7 million.



Net income (loss)

Consolidated Three months ended December 31,
----------------------------------------------------------------------------
($ 000s, except per unit data) 2007 2006 % Change
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Net income (loss) $ 68,545 $ (25,501) -
Per weighted aver age unit
- basic and diluted (1) $ 0.28 $ (0.12) -
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(1) Based on weighted average number of trust units outstanding including
the dilutive impact of the unit option plan, exchangeable shares and
convertible debentures.


Net income for the fourth quarter of 2007 increased to $68.5 million compared to a loss of $25.5 million in the comparable 2006 quarter. The increase was driven by a 39 percent increase in earnings before interest, taxes, depletion, depreciation, accretion and other non-cash items (EBITDA) reflecting higher operating results in all three operating segments and a $161.7 million dilution gain related to Provident's change in ownership of the MLP due to the USOGP natural gas asset acquisition, as well as lower non-cash unit based compensation and a future income tax recovery. These items were partially offset by a $219.7 million fourth quarter change in unrealized loss on financial derivative instruments that extend to January 2013.

The COGP business segment had net income of $16.9 million compared to a 2006 fourth quarter net loss of $8.2 million. A 24 percent increase in EBITDA combined with a future income tax recovery were partially offset by unrealized losses on derivative financial instruments and increased depletion expense.

The Midstream segment recognized a net loss of $62.0 million in the fourth quarter of 2007, compared to $11.0 million of net loss in the fourth quarter of 2006. Midstream results include EBITDA of $89.4 million in 2007 compared to $74.4 million in the fourth quarter of 2006. Midstream EBITDA reflected an increase in operating margins for all three business lines within the Midstream segment. Offsetting this strong EBITDA were unrealized losses on outstanding financial derivative instruments amounting to $161.8 million for the fourth quarter of 2007 (2006 - $28.7 million). Under generally accepted accounting principles, these unrealized "mark-to-market" amounts, which relate to financial instruments with effective periods ranging from 2008 through January 2013, were required to be fully recognized in the financial statements of Provident, affecting current quarter earnings.

USOGP generated net income of $113.6 million in the fourth quarter of 2007 with a comparative net loss of $6.3 million for 2006. The significant increase in net income was due to a fourth quarter 2007 dilution gain generated as Provident's ownership of the MLP was reduced when the MLP issued equity to finance the USOGP natural gas asset acquisition.

Reconciliation of non-GAAP measure

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




EBITDA Reconciliation Three months ended December 31,
----------------------------------------------------------------------------
($ 000s) 2007 2006 % Change
----------------------------------------------------------------------------
----------------------------------------------------------------------------
EBITDA $ 195,802 $ 140,919 39
Adjusted for:
Cash interest (22,285) (16,308) 37
Unrealized loss on financial
derivative instruments (243,970) (24,293) 904
Dilution gain 161,732 - -
Depletion, depreciation and
accretion and other non-cash
expenses (105,589) (100,084) 6
----------------------------------------------------------------------------
(Loss) income before taxes and
non-controlling interests $ (14,310) $ 234 -
----------------------------------------------------------------------------
----------------------------------------------------------------------------


Reconciliation of funds flow
from operations to distributions Three months ended December 31,
----------------------------------------------------------------------------
2007 2006 % Change
----------------------------------------------------------------------------
Cash provided by operating
activities $ 137,330 $ 162,889 (16)
Change in non-cash operating
working capital 38,149 (41,424) -
Site restoration expenditures 2,084 1,214 72
----------------------------------------------------------------------------
Funds flow from operations 177,563 122,679 45
Distributions to non-controlling
interests (22,124) (4,715) 369
Cash retained for financing and
investing activities (66,376) (42,391) 57
----------------------------------------------------------------------------
Distributions to unitholders 89,063 75,573 18
Accumulated cash distributions,
beginning of period 1,171,114 851,252 38
----------------------------------------------------------------------------
Accumulated cash distributions,
end of period $ 1,260,177 $ 926,825 36
----------------------------------------------------------------------------
Cash distributions per unit $ 0.36 $ 0.36 -
----------------------------------------------------------------------------
----------------------------------------------------------------------------


Taxes

Consolidated Three months ended December 31,
----------------------------------------------------------------------------
($ 000s) 2007 2006 % Change
----------------------------------------------------------------------------
Capital tax expense $ 510 $ 452 13
Current and withholding tax
(recovery) expense (261) 1,433 -
Future income tax (recovery) expense (57,593) 21,253 -
----------------------------------------------------------------------------
$ (57,344) $ 23,138 -
----------------------------------------------------------------------------
----------------------------------------------------------------------------


Fourth quarter Saskatchewan capital taxes totaled $0.5 million, consistent with the $0.5 million recorded in the fourth quarter of 2006.

The current and withholding tax recovery was $0.3 million in the fourth quarter of 2007 with a comparative expense of $1.4 million in the fourth quarter of 2006. These taxes arise from Provident's U.S. based operations and reflect a decrease in fourth quarter income subject to tax, primarily in U.S. Midstream operations.

The 2007 fourth quarter future tax recovery of $57.6 million compares to an expense of $ 21.3 million in the fourth quarter of 2006. The future tax recovery in the fourth quarter of 2007 resulted from an increased loss for tax purposes in the Canadian operations and the impact of income tax rate changes.



Interest expense


Consolidated Three months ended December 31,
----------------------------------------------------------------------------
($ 000s, except as noted) 2007 2006 % Change
----------------------------------------------------------------------------
Interest on bank debt $ 17,299 $ 11,162 55
Weighted-average interest
rate on bank debt 5.95% 5.33% 12
Interest on 8.75% convertible
debentures 438 557 (21)
Interest on 8.0% convertible
debentures 503 543 (7)
Interest on 6.5% convertible
debentures 1,609 1,609 -
Interest on 6.5% convertible
debentures 2,436 2,437 -
----------------------------------------------------------------------------
Total cash interest $ 22,285 $ 16,308 37
----------------------------------------------------------------------------
----------------------------------------------------------------------------

Weighted average interest rate on
all long-term debt 6.12% 5.75% 6

Debenture accretion and other
non-cash interest expense 2,026 1,708 19
----------------------------------------------------------------------------
Total interest expense $ 24,311 $ 18,016 35
----------------------------------------------------------------------------
----------------------------------------------------------------------------


Cash interest expense increased for the quarter as compared to the same quarter in 2006 due to the increase in the overall size of Provident, with commensurate increases in debt levels. Increased debt levels are a direct result of the third quarter 2006 Rainbow asset acquisition, the second quarter 2007 Capitol acquisition and the fourth quarter 2007 USOGP natural gas asset acquisition.

Commodity price risk management program

A summary of Provident's risk management contracts executed during the fourth quarter of 2007 is contained in the following tables.



Activity in the Fourth Quarter:

COGP

Volume
Year Product (Buy)/Sell Terms Effective Period
----------------------------------------------------------------------------
2008 Crude Oil 150 Bpd Puts US $75.00 per bbl January 1-December 31
1,000 Bpd Puts US $67.50 per bbl January 1-December 31
----------------------------------------------------------------------------
----------------------------------------------------------------------------

USOGP

Volume
Year Product (Buy)/Sell Terms Effective Period
----------------------------------------------------------------------------
2008 Crude Oil 250 Bpd Participating Swap US
$70.00 per bbl (61.8%
above the floor price) July 1-December 31
2009 Crude Oil 250 Bpd Participating Swap US
$70.00 per bbl (61.8%
above the floor price) January 1-December 31
2010 Crude Oil 250 Bpd Participating Swap US
$70.00 per bbl (61.8%
above the floor price) January 1-March 31
500 Bpd Participating Swap US
$70.00 per bbl (37.3%
above the floor price) April 1-September 30
----------------------------------------------------------------------------
----------------------------------------------------------------------------


Midstream

Volume
Year Product (Buy)/Sell Terms Effective Period
----------------------------------------------------------------------------
2008 Crude Oil (10,535) Bpd US $86.93 per bbl (4) January 1-March 31
Propane 3,225 Bpd US $1.5308 per gallon
(6) (9) January 1-January 31
1,206 Bpd US $1.5382 per gallon
(6) (9) February 1-February 29
10,287 Bpd US $1.4595 per gallon
(4) (6) January 1-March 31
Normal
Butane 2,258 Bpd US $1.8148 per gallon
(7) (9) January 1-January 31
2,230 Bpd US $1.647 per gallon
(4) (7) January 1-March 31
ISO Butane 1,720 Bpd US $1.6424 per gallon
(4) (8) January 1-March 31
Power (20) MW/hpd Cdn $76.43 per MW/h(12) January 1-December 31
2009 Crude Oil 598 Bpd Participating Swap US
$75.64 per bbl (55.7%
above the floor price) July 1-November 30
500 Bpd Participating Swap Cdn
$73.38 per bbl (48.9%
above the floor
price) September 1-November 30
Natural Gas (2,792) Gjpd Participating Swap Cdn
$7.73 per gj (39% below
the ceiling price) July 1-November 30
(2,810) Gjpd Cdn $6.62 per gj September 1-October 31
(2,810) Gjpd Costless Collar Cdn
$6.20 floor, Cdn $7.10
ceiling September 1-October 31
Foreign
Exchange Sell US $596,166 per
month @0.9815 (5) July 1-October 31
Sell US $1,686,650 per
month @0.9620 (5) September 1-October 31
Sell US $1,163,100 per
month @1.013 (5) November 1-November 30
2010 Crude Oil 376 Bpd Participating Swap Cdn
$70.91 per bbl (56%
above the floor price) July 1-October 31
820 Bpd Participating Swap US
$73.63 per bbl (51.8%
above the floor price) January 1-November 30
Natural Gas(4,089) Gjpd Participating Swap Cdn
$7.62 per gj (31.3%
below the ceiling
price) January 1-November 30
(3,529) Gjpd Cdn $6.69 per gj July 1-October 31
Foreign
Exchange Sell US $582,821 per
month @1.0159 (5) January 1-August 31
Sell US $1,407,419 per
month @0.9781 (5) July 1-August 31
Sell US $587,903 per
month @1.0165 (5) July 1-November 30
Sell US $2,254,103 per
month @0.9577 (5) September 1-October 31
Sell US $1,750,992 per
month @1.0176 (5) September 1-November 30
2011 Crude Oil 250 Bpd Participating Swap US
$63.00 per bbl (64%
above the floor price) January 1-December 31
Natural Gas (1,405)Gjpd Cdn $6.91 per gj January 1-December 31
Foreign
Exchange Sell US $479,063 per
month @0.9725 (5) January 1-December 31
2012 Crude Oil 1,141 Bpd Participating Swap US
$66.67 per bbl (59%
above the floor price) April 1-December 31
500 Bpd Cdn $71.88 per bbl October 1-December 31
250 Bpd Participating Swap Cdn
$71.50 per bbl (50%
above the floor price) October 1-December 31
Natural Gas (7,827)Gjpd Cdn $6.83 per gj April 1-December 31
Foreign
Exchange Sell US $1,437,986 per
month @0.9657 (5) July 1-December 31
Sell US $976,436 per
month @0.9413 (5) April 1-October 31
Sell US $1,634,227 per
month @0.9832 (5) October 1-December 31
2013 Crude Oil 250 Bpd Cdn $75.32 per bbl January 1-January 31
750 Bpd Participating Swap US
$70.92 per bbl (50.6%
above the floor price) January 1-January 31
250 Bpd Participating Swap Cdn
$71.50 per bbl (50%
above the floor price) January 1-January 31
Natural Gas (7,025)Gjpd Cdn $7.19 per gj January 1-January 31
Foreign
Exchange Sell US $1,651,990 per
month @0.9832 (5) January 1-January 31
----------------------------------------------------------------------------
----------------------------------------------------------------------------


Corporate

Volume
Year Product (Buy)/Sell Terms Effective Period
----------------------------------------------------------------------------
2008 Foreign
Exchange Sell US $9,000,000 @.9701 (5.1) January 25
Sell US $3,000,000 @1.0105 (5.1) February 25
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(1) The above table represents a number of transactions entered into over
an extended period of time.
(2) Natural Gas contracts are settled against AECO monthly index.
(3) Crude Oil contracts are settled against NYMEX WTI calendar average.
(4) Conversion of Crude Oil BTU positions to liquids.
(5) US dollar contracts settled against Bank of Canada noon rate average.
(5.1) US dollar cashflows sold forward.
(6) Propane contracts are settled against Belvieu C3 TET.
(7) Normal Butane contracts are settled against Belvieu NC4 NON-TET.
(8) ISO Butane contracts are settled against Belvieu IC4 NON-TET.
(9) Midstream inventory price stabilization contracts.
(10) Natural Gas contracts settle against Natural Gas - Michcon Citygate
Inside FERC.
(11) Settles quarterly against 3M CAD BA interest rate.
(12) Power contracts are settled monthly against the average hourly price
of Electricity as published by the AESO in $/MWh.


Settlement of commodity contracts

The following is a summary of the net cash flow to settle Commodity contracts during the fourth quarter of 2007. For comparative purposes, the 2006 amounts are also summarized.

a) Crude oil

For the quarter ending December 31, 2007, Provident paid $15.2 million (2006 - $1.3 million received) to settle various oil market based contracts on an aggregate volume of 1.0 million barrels (2006 - 0.6 million barrels).

b) Natural Gas

For the quarter ending December 31, 2007, Provident received $5.1 million (2006 - $3.7 million received) to settle various natural gas market based contracts on an aggregate volume of 3.2 million gj's (2006 - 4.2 million gj's).

c) Midstream

For the quarter ending December 31, 2007 Provident received $0.2 million (2006 - $3.6 million) to settle midstream oil market based contracts on an aggregate volume of 0.4 million barrels (2006 - 0.3 million barrels) and paid $16.8 million (2006 - $8.8 million) to settle midstream natural gas market based contracts on an aggregate volume of 6.8 million gj's (2006 - 4.7 million gj's). In addition, Provident paid $26.6 million (2006 - $10.6 million received) to settle midstream NGL market based contracts on an aggregate volume of 2.0 million barrels (2006 - 1.9 million barrels).

d) Foreign exchange contracts

For the quarter ending December 31, 2007 Provident received $6.3 million to settle various foreign exchange based contracts.

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.



COGP segment review

Crude oil price and liquids

COGP Three months ended December 31,
----------------------------------------------------------------------------
($ per bbl) 2007 2006 % Change
----------------------------------------------------------------------------

Oil per barrel
WTI (US$) $ 90.68 $ 60.21 51
Exchange rate (from US$ to Cdn$) $ 0.98 $ 1.14 (14)
WTI expressed in Cdn$ $ 89.03 $ 68.64 30
----------------------------------------------------------------------------
----------------------------------------------------------------------------

Realized pricing before financial
derivative instruments
Light/Medium oil $ 65.18 $ 51.93 26
Heavy oil $ 43.36 $ 25.82 68
Natural gas liquids $ 63.63 $ 47.46 34
----------------------------------------------------------------------------
Crude oil and natural gas liquids $ 61.94 $ 46.39 34
----------------------------------------------------------------------------
----------------------------------------------------------------------------


The above prices are net of transportation expense.

In the fourth quarter of 2007 COGP's realized oil and natural gas liquids price, prior to the impact of financial derivative instruments, increased by 34 percent to $61.94 per barrel compared to $46.39 per barrel in the fourth quarter of 2006. The increase was related to a 51 percent higher US$ WTI crude oil price, partially offset by a stronger Canadian dollar and wider differentials.



Natural gas price

COGP Three months ended December 31,
----------------------------------------------------------------------------
($ per mcf) 2007 2006 % Change
----------------------------------------------------------------------------
AECO monthly index (Cdn$ per mcf) $ 6.00 $ 6.36 (6)
Corporate natural gas price per
mcf before financial derivative
instruments (Cdn$) $ 6.08 $ 6.73 (10)
----------------------------------------------------------------------------
----------------------------------------------------------------------------


COGP's fourth quarter 2007 realized natural gas price, prior to the impact of financial derivative instruments, decreased 10 percent as compared to the fourth quarter of 2006, higher than the decrease in the benchmark AECO index price of six percent. Provident's gas portfolio includes aggregator contracts sold on a term basis that can differ from the benchmark price and sells to the spot market on monthly or daily indices and receives prices which take into account heat content. Provident's realized prices and changes in prices can therefore differ from benchmark indices.



Production

COGP Three months ended December 31,
----------------------------------------------------------------------------
2007 2006 % Change
----------------------------------------------------------------------------
Daily production
Crude oil - Light/Medium (bpd) 9,483 6,569 44
- Heavy (bpd) 1,769 1,838 (4)
Natural gas liquids (bpd) 1,277 1,331 (4)
Natural gas (mcfd) 92,584 97,489 (5)
----------------------------------------------------------------------------
Oil equivalent (boed) (1) 27,960 25,986 8
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(1) Provident reports equivalent production converting natural gas to oil
on a 6:1 basis.


Production increased eight percent to 27,960 boed during the fourth quarter of 2007 as compared to 25,986 boed in 2006. The increase was primarily a result of the acquisitions of Capitol Resources Ltd. ("Capitol") on June 19, 2007 and Triwest Energy Inc. ("Triwest") on December 3, 2007, as well as an active drilling and optimization program. The Capitol acquisition became COGP's newest core area, Dixonville, and the Triwest acquisition has been rolled up into the Southeast Saskatchewan core area. The overall increase in production was partially offset by natural production declines.

Production for the fourth quarter of 2007 was weighted 55 percent natural gas, 39 percent medium/light crude oil and natural gas liquids and six percent heavy oil. This compared to fourth quarter 2006 production weighted 63 percent natural gas, 30 percent medium/light oil and natural gas liquids and seven percent heavy oil. Quarter-over-quarter, the change in mix reflected the Capitol and Triwest acquisitions which were primarily light/medium crude oil production and natural production.



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

Three months ended December 31,
----------------------------------------------------------------------------
COGP 2007 2006 % Change
----------------------------------------------------------------------------
Daily Production - by area (boed) (1)
West Central Alberta 6,762 7,648 (12)
Southern Alberta 5,493 6,022 (9)
Northwest Alberta 4,714 4,731 -
Dixonville 4,090 - -
Southeast Saskatchewan 2,144 1,627 32
Southwest Saskatchewan 1,527 2,545 (40)
Lloydminster 3,217 3,330 (3)
Other 13 83 (84)
----------------------------------------------------------------------------
27,960 25,986 8
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(1) Provident reports equivalent production converting natural gas to oil
on a 6:1 basis.


Internal development activities included 35.8 net wells drilled during the quarter ended December 31, 2007 with a 97 percent success rate. Production results at Dixonville have met internal expectations, however, Dixonville did experience significant downtime during December due to cold weather conditions. Optimization of the Dixonville production and facilities are ongoing. In the fourth quarter of 2007, activity at Southern Saskatchewan focused on light/medium conventional oil drilling in southeast Saskatchewan. The production increase in Southeast Saskatchewan is primarily a result of the Triwest acquisition and the related drilling program. Results from the Triwest assets during the quarter exceeded internal expectations. Provident has shifted some capital expenditures from shallow gas drilling in Southwest Saskatchewan to other areas to enhance the return on capital. In Southwest Saskatchewan, Provident focused primarily on operating cost initiatives such as a water injection well and compressor optimization. In both Southern Alberta and West Central Alberta, Provident has managed production declines in a lower gas price environment by successfully reactivating wells and conducting workovers. Northwest Alberta's production was flat quarter over quarter although there was some unfavorable cold weather in December, which resulted in a unit compressor and pump jack failure impacting production. In Lloydminster, Provident is working to enhance the area cost structure through production optimization and increased water disposal capacity.



Revenue and royalties

COGP Three months ended December 31,
----------------------------------------------------------------------------
($ 000s except per boe and mcf data) 2007 2006 % Change
----------------------------------------------------------------------------

Oil
Revenue $ 63,920 $ 35,754 79
Realized loss on financial
derivative instruments (4,675) (653) 616
Royalties (12,491) (6,651) 88
----------------------------------------------------------------------------
Net revenue $ 46,754 $ 28,450 64
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Net revenue (per barrel) $ 45.17 $ 36.78 23
Royalties as a percentage of revenue 19.5% 18.6%
----------------------------------------------------------------------------

Natural gas
Revenue $ 51,766 $ 60,337 (14)
Realized gain on financial
derivative instruments 5,174 3,802 36
Royalties (9,437) (11,680) (19)
----------------------------------------------------------------------------
Net revenue $ 47,503 $ 52,459 (9)
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Net revenue (per mcf) $ 5.58 $ 5.85 (5)
Royalties as a percentage
of revenue 18.2% 19.4%
----------------------------------------------------------------------------

Natural gas liquids
Revenue $ 7,477 $ 5,811 29
Royalties (1,882) (1,229) 53
----------------------------------------------------------------------------
Net revenue $ 5,595 $ 4,582 22
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Net revenue (per barrel) $ 47.62 $ 37.42 27
Royalties as a percentage of revenue 25.2% 21.1%
----------------------------------------------------------------------------

Total
Revenue $ 123,163 $ 101,902 21
Realized gain on financial
derivative instruments 499 3,149 (84)
Royalties (23,810) (19,560) 22
----------------------------------------------------------------------------
Net revenue $ 99,852 $ 85,491 17
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Net revenue (per boe) $ 38.81 $ 35.76 9
Royalties as a percentage of revenue 19.3% 19.2%
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Note: the above revenue, net revenue and net revenue per boe figures are
presented net of transportation expenses.


In the fourth quarter of 2007, COGP production revenue was $123.2 million, an increase of 21 percent from $101.9 million in 2006. The increase in revenue is a result of an eight percent increase in production and a 34 percent increase in crude oil and natural gas liquids prices, partially offset by a decrease in Provident's realized natural gas price. Total royalties as a percentage of revenue have remained relatively constant at 19.3 percent. The preceding factors, as well as the change in realized gain of financial derivative instruments account for net revenue of $99.9 million in the fourth quarter of 2007, 17 percent above the $85.5 million recorded in the fourth quarter of 2006. Net revenue per boe in the fourth quarter of 2007 was $38.81 per boe, an increase of nine percent from $35.76 per boe in the fourth quarter of 2006.



Production expenses

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

Production expenses $ 29,644 $ 28,302 5
Production expenses (per boe) $ 11.52 $ 11.84 (3)
----------------------------------------------------------------------------
----------------------------------------------------------------------------


Fourth quarter 2007 production expenses increased five percent to $29.6 million from $28.3 million in the comparable 2006 quarter mainly due to the eight percent increase in production volumes. On a boe basis, quarter over quarter production expenses have decreased by three percent to $11.52 per boe from $11.84 per boe in the comparable 2006 quarter. The per boe decrease reflects the lower operating costs per boe associated with the Capitol and Triwest assets acquired.



Operating netback

COGP Three months ended December 31,
----------------------------------------------------------------------------
($ per boe) 2007 2006 % Change
----------------------------------------------------------------------------
Netback per boe
Gross production revenue $ 47.88 $ 42.62 12
Royalties (9.26) (8.18) 13
Operating costs (11.52) (11.84) (3)
----------------------------------------------------------------------------
Field operating netback 27.10 22.60 20
Realized gain on financial derivative
instruments 0.19 1.32 (86)
----------------------------------------------------------------------------
Operating netback after realized financial
derivative instruments $ 27.29 $ 23.92 14
----------------------------------------------------------------------------
----------------------------------------------------------------------------


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

The fourth quarter 2007 field operating netback increased 20 percent to $27.10 per boe from $22.60 per boe in the comparable quarter in 2006. The higher field operating netback reflects COGP's increase in crude oil and natural gas liquids production mix up to 39 percent from 30 percent in the comparable quarter in 2006. This, coupled with the 34 percent increase in crude oil and natural gas liquids prices, partially offset by the lower realized price for natural gas, accounts mainly for the increase. Royalties, which are price sensitive, increased by 13 percent on a boe basis reflecting the higher total liquids mix prices, prior to the impact of financial derivative instruments. The fourth quarter 2007 operating netback after financial derivative instruments increased by 14 percent to $27.29 from $23.92 reflecting the preceding factors as well as the 2007 fourth quarter gain on financial derivative instruments of $0.19 per boe compared to a gain of $1.32 per boe in the comparable quarter in 2006.



General and administrative

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

Cash general and administrative $ 5,583 $ 6,410 (13)
Non-cash unit based compensation (3,014) 1,182 -
----------------------------------------------------------------------------

$ 2,569 $ 7,592 (66)
Cash general and administrative (per boe) $ 2.17 $ 2.68 (19)
----------------------------------------------------------------------------
----------------------------------------------------------------------------


Cash general and administrative expenses for COGP in the fourth quarter decreased 13 percent to $5.6 million from $6.4 million recorded in the 2006 comparable quarter. On a boe basis the cash general and administrative expenses recorded in fourth quarter 2007 decreased 19 percent to $2.17 from $2.68 in the fourth quarter of 2006. The decrease in cash general and administrative expenses reflects fourth quarter 2007 accrual adjustments.

Non-cash unit based compensation decreased to a recovery of $3.0 million in the fourth quarter of 2007 from an expense of $1.2 million in the fourth quarter of 2006. The recovery reflects a reduction to employee incentive costs based on the total return performance of the Trust as measured against an industry peer group.



Capital expenditures

COGP Three months ended December 31,
----------------------------------------------------------------------------
($ 000s) 2007 2006
----------------------------------------------------------------------------
Capital expenditures - by category
Geological, geophysical and land $ 619 $ 1,067
Drilling and recompletions 37,485 14,988
Facilities and equipment 5,827 1,365
Other capital 8,614 855
----------------------------------------------------------------------------
Total additions $ 52,545 $ 18,275
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Capital expenditures - by area
West central Alberta $ 2,159 $ 3,968
Southern Alberta 1,878 3,000
Northwest Alberta 5,892 4,598
Dixonville 26,130 -
Southeast Saskatchewan 1,845 384
Southwest Saskatchewan 2,913 4,006
Lloydminster 3,383 1,738
Office and other 8,345 581
----------------------------------------------------------------------------
Total additions $ 52,545 $ 18,275
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Property acquisitions, net $ 1,481 $ 8,678
----------------------------------------------------------------------------


In the fourth quarter of 2007, Provident's COGP business unit spent $44.2 million on capital expenditures before office and other capital costs. Internal development activities included 35.8 net wells drilled during the quarter with a 97 percent success rate as Provident continues with the expanded drilling program. Provident's most active area in the fourth quarter of 2007 was its newest core area, Dixonville. Dixonville expenditures were $26.1 million including 26.0 net horizontal wells drilled. Provident spent $5.9 million in Northwest Alberta primarily on drilling and completion activities and facility work associated with the start up of the 2007/2008 winter drilling program including 2.0 net wells drilled in the fourth quarter of 2007. At December 31, 2007, Provident was ahead of its planned winter drilling schedule at Northwest Alberta. In the Southeast and Southwest Saskatchewan core areas, $4.8 million was spent primarily on shallow gas drilling and the continuation of the drilling program for the Triwest acquired assets, resulting in 3.8 net wells drilled, as well as facility work focused on infrastructure to tie-in future shallow gas production in Southwest Saskatchewan. In the Lloydminster core area, $3.4 million was spent primarily on drilling and recompletion activities and facility work. This included 1.0 net well drilled and Provident is working to enhance the area cost structure through production optimization and increased water disposal capacity. In West Central Alberta, $2.2 million was spent largely on non-operated drilling and facility work continuing with its strategy of farming out high risk exploration land to enhance cash flow resulting in 1.2 net low risk wells. The production in West Central Alberta requires relatively less capital to manage its decline. In Southern Alberta, $1.9 million was primarily spent on drilling activities and recompletions in connection with the shallow gas drilling program, resulting in 1.8 net wells drilled.

In the fourth quarter of 2007, COGP also spent $1.5 million on property acquisitions relating to additional working interests in Southern Alberta.

In addition, $8.3 million was spent on office and other in the fourth quarter of 2007, related to office equipment and furniture for the new office space to be occupied in 2008.



Depletion, depreciation and accretion (DD&A)

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

DD&A $ 70,865 $ 58,617 21
DD&A (per boe) $ 27.55 $ 24.52 12
----------------------------------------------------------------------------
----------------------------------------------------------------------------


The COGP DD&A rate of $27.55 per boe for the fourth quarter of 2007 increased by 12 percent compared to $24.52 per boe for the fourth quarter of 2006. The increase was primarily as a result of the Capitol and Triwest acquisitions in 2007.

Accretion expense associated with asset retirement obligations was $0.7 million in the fourth quarter of 2007 compared to $0.5 million in the fourth quarter of 2006.

USOGP segment review

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

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

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

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

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



Crude oil, natural gas liquids and natural gas pricing

The following prices are net of transportation expenses.

USOGP Three months ended December 31,
----------------------------------------------------------------------------
2007 2006 % Change
----------------------------------------------------------------------------
Realized pricing before financial derivative
Light/medium oil and natural gas liquids
(Cdn$ per bbl) $ 71.65 $ 56.96 26
Natural Gas (Cdn $ per mcf) $ 7.33 $ 5.87 25
----------------------------------------------------------------------------
----------------------------------------------------------------------------


The majority of USOGP oil production is light, sweet crude that attracts smaller differentials to benchmark prices relative to heavier blends. Realized crude oil and natural gas liquids pricing before financial derivative instruments in the fourth quarter of 2007 was 26 percent higher than the fourth quarter of 2006, reflecting higher WTI crude prices, partially offset by the stronger Canadian dollar.

Realized natural gas pricing saw a 25 percent increase to $7.33 per mcf in the fourth quarter of 2007 when compared to the fourth quarter of 2006. Natural gas represents approximately 43 percent of total boe production of USOGP. The newly acquired Michigan properties have favorable natural gas supply/demand characteristics as the state has been importing an increasing percentage of its natural gas.



Production

Three months ended December 31,
----------------------------------------------------------------------------
USOGP 2007 2006 % Change
----------------------------------------------------------------------------
Daily production - by product
Crude oil - Light/Medium (bpd) 11,238 7,330 53
Natural gas liquids (bpd) 335 14 2,293
Natural gas (mcfd) 52,094 2,540 1,951
----------------------------------------------------------------------------
Oil equivalent (boed) (1) 20,255 7,767 161
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(1) Provident reports equivalent production converting natural gas to oil
on a 6:1 basis.


Three months ended December 31,
----------------------------------------------------------------------------
USOGP 2007 2006 % Change
----------------------------------------------------------------------------
Daily Production - by area (boed) (1)
Los Angeles 4,529 3,772 20
Santa Maria - Orcutt 1,575 1,528 3
Wyoming 2,516 2,467 2
Texas 318 - -
Florida 1,940 - -
Michigan/Indiana/Kentucky 9,377 - -
----------------------------------------------------------------------------
20,255 7,767 161
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(1) Provident reports equivalent production converting natural gas to oil
on a 6:1 basis.


USOGP production increased 12,488 boe per day or 161 percent in the fourth quarter of 2007 when compared to the fourth quarter of 2006. The increase is primarily attributable to acquisitions made by USOGP in 2007, which included fields in Michigan, Indiana, Kentucky, Los Angeles, Florida and Texas. Fourth quarter 2007 production from the MLP was 17,682 boed, while production from BreitBurn was 2,573 boed.

Revenue and royalties

The following table outlines USOGP revenue and royalties by product line. The table excludes revenues earned from operating certain properties ($0.7 million in the fourth quarter of 2007 (2006 - $0.2 million)) on behalf of third parties.



USOGP Three months ended December 31,
----------------------------------------------------------------------------
($ 000s except per boe and mcf data) 2007 2006% Change
----------------------------------------------------------------------------

Oil and natural gas liquids
Revenue $ 71,293 $ 38,610 85
Realized (loss) gain on financial derivative
instruments (8,838) 1,892 -
Royalties (8,399) (3,773) 123
----------------------------------------------------------------------------
Net revenue $ 54,056 $ 36,729 47
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Net revenue (per barrel) $ 54.33 $ 54.36 -
Royalties as a percentage of revenue 11.8% 9.8%
----------------------------------------------------------------------------

Natural gas
Revenue $ 35,136 $ 1,373 2,459
Royalties (5,872) (184) 3,091
----------------------------------------------------------------------------
Net revenue $ 29,264 $ 1,189 2,361
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Net revenue (per mcf) $ 6.11 $ 5.09 20
Royalties as a percentage of revenue 16.7% 13.4%
----------------------------------------------------------------------------

Total
Revenue $106,429 $ 39,983 166
Realized (loss) gain on financial derivative
instruments (8,838) 1,892 -
Royalties (14,271) (3,957) 261
----------------------------------------------------------------------------
Net revenue $ 83,320 $ 37,918 120
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Net revenue (per boe) $ 46.45 $ 53.06 (12)
Royalties as a percentage of revenue 13.4% 9.9%
----------------------------------------------------------------------------
Note: the above revenue, net revenue and net revenue per boe figures are
presented net of transportation expenses. Per boe figures are
calculated using sales volumes, which differ from production volumes
due to changes in inventory levels at the Florida properties,
acquired in the second quarter of 2007.


Revenue for the quarter ended December 31, 2007 was $106.4 million or 166 percent higher than the quarter ended December 31, 2006. The increase was primarily attributable to a 161 percent increase in production volumes in the fourth quarter of 2007 as compared to the fourth quarter of 2006. Net revenue is $83.3 million or 120 percent higher than the $37.9 million of net revenue in the fourth quarter 2006, reflecting a realized loss on financial derivative instruments in the fourth quarter of 2007. Royalties as a percentage of revenue have increased as royalties at the Michigan, Wyoming, Texas and Florida properties are higher than those incurred at the Southern California operations.



Production expenses

USOGP Three months ended December 31,
----------------------------------------------------------------------------
($ 000s, except per boe amounts) 2007 2006 % Change
----------------------------------------------------------------------------
Production expenses $ 29,936 $ 15,534 93
Production expenses (per boe) $ 16.69 $ 21.74 (23)
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Note: Per boe figures are calculated using sales volumes, which differ from
production volumes due to changes in inventory levels at the Florida
properties, acquired in the second quarter of 2007.


Production expenses increased 93 percent to $29.9 million in the fourth quarter of 2007 compared to $15.5 million for the comparable quarter in 2006. Operating costs per boe have decreased 23 percent to $16.69 in the fourth quarter of 2007 from $21.74 in the comparable quarter in 2006. This increase primarily reflects all the 2007 acquisitions. The per unit cost is lower reflecting the USOGP natural gas asset acquisition which has lower production costs than other USOGP properties.



Operating netback

USOGP Three months ended December 31,
----------------------------------------------------------------------------
($ per boe) 2007 2006 % Change
----------------------------------------------------------------------------
USOGP oil equivalent netback per boe
Gross production revenue $ 59.33 $ 55.95 6
Royalties (7.96) (5.54) 44
Operating costs (16.69) (21.74) (23)
----------------------------------------------------------------------------
Field operating netback $ 34.68 $ 28.67 21
Realized (loss) gain on financial derivative
instruments (4.92) 2.65 -
----------------------------------------------------------------------------
Operating netback after realized financial
derivative instruments $ 29.76 $ 31.32 (5)
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Note: Per boe figures are calculated using sales volumes, which differ from
production volumes due to changes in inventory levels at the Florida
properties, acquired in the second quarter of 2007.


The fourth quarter 2007 field operating netback of $34.68 per boe was 21 percent above the $28.67 per boe in the comparable quarter of 2006. The increase reflects higher crude oil and natural gas prices. In addition, operating costs per boe were lower than the fourth quarter of 2006. The fourth quarter 2007 operating netback after realized financial derivative instruments of $29.76 per boe is five percent lower than the $31.32 per boe for the fourth quarter of 2006 reflecting the preceding factors offset by a realized loss on financial derivative instruments as compared to a gain in 2006.



General and administrative

USOGP Three months ended December 31,
----------------------------------------------------------------------------
($ 000s, except per boe amounts) 2007 2006 % Change
----------------------------------------------------------------------------
Cash general and administrative $ 10,717 $ 6,839 57
Non-cash unit based compensation 5,846 7,800 (25)
----------------------------------------------------------------------------
$ 16,563 $ 14,639 13

Cash general and administrative (per boe) $ 5.75 $ 9.57 (40)
----------------------------------------------------------------------------
----------------------------------------------------------------------------


Cash general and administrative expenses in the fourth quarter of $10.7 million or $5.75 per boe, is 57 percent higher than the fourth quarter of 2006. The increase reflects higher staffing levels due to the fourth quarter USOGP natural gas asset acquisition.

Non-cash unit based compensation expense was $5.8 million in the fourth quarter of 2007 compared to $7.8 million in the fourth quarter of 2006. The decrease in incentive plan costs is primarily driven by the startup costs associated with new incentive plans as a result of the initial public offering of the MLP completed in the fourth quarter of 2006.



Capital expenditures

USOGP Three months ended December 31,
----------------------------------------------------------------------------
($ 000s) 2007 2006
----------------------------------------------------------------------------
Capital expenditures - by category
Geological, geophysical and land $ 44 $ 104
Drilling and r ecompletions 11,900 6,796
Facilities and equipment 5,050 5,365
Other capital 1,158 2,049
----------------------------------------------------------------------------
Total additions $ 18,152 $ 14,314
----------------------------------------------------------------------------
----------------------------------------------------------------------------

Property acquisitions, net $764,959 $ -
----------------------------------------------------------------------------


USOGP capital expenditures for the fourth quarter of 2007 totaled $18.2 million. The majority of the expenditures were directed at drilling, optimization and facility upgrades at the newly acquired fields in Michigan, and the ongoing work at the Orcutt fields.



Depletion, depreciation and accretion (DD&A)

USOGP Three months ended December 31,
----------------------------------------------------------------------------
($ 000s, except per boe data) 2007 2006 % Change
----------------------------------------------------------------------------
DD&A $ 22,201 $ 9,269 140
DD&A (per boe) $ 11.91 $ 12.97 (8)
----------------------------------------------------------------------------
----------------------------------------------------------------------------


The USOGP's DD&A rate is low due to the long-lived nature of the assets. On a per boe basis the DD&A rate was down $1.06 or eight percent in the fourth quarter of 2007 when compared to the fourth quarter of 2006. The change reflects higher overall depletion costs related to the recent producing property acquisitions as well as year end 2006 DD&A rate adjustments.

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.

Midstream business unit results can be summarized as follows:



Three months ended December 31,
----------------------------------------------------------------------------
----------------------------------------------------------------------------
($ 000s) 2007 2006 % Change
----------------------------------------------------------------------------
Empress East Margin $ 77,110 $ 29,762 159
Redwater West Margin 41,709 30,344 37
Commercial Services Margin 19,587 13,248 48
----------------------------------------------------------------------------
Gross operating margin 138,406 73,354 89
Realized (loss) gain on financial derivative
instruments (38,631) 5,397 -
Cash general and administrative expenses (6,355) (6,710) (5)
Foreign exchange (loss) gain and other (3,997) 2,381 -
----------------------------------------------------------------------------
Midstream EBITDA $ 89,423 $ 74,422 20
----------------------------------------------------------------------------
----------------------------------------------------------------------------


Gross operating margin

The Empress East business line extracts NGLs from natural gas at the Empress straddle plants and sells finished products into markets in Central Canada and the Eastern United States. The margin in this business is determined primarily by the "frac spread ratio", which is the ratio between crude oil prices and natural gas prices. The higher the ratio, the better this business line will perform. There is also a differential between propane, butane and condensate prices and crude oil prices which can change prices received and margins realized for Midstream products separate from frac spread ratio changes. In the fourth quarter of 2007, the margin for this business line was $77.1 million (2006 - $29.8 million). This increase is primarily the result of 33 percent higher propane-plus prices with product costs only increasing by four percent. In addition to product acquired or produced in the quarter, over 300,000 barrels of propane-plus finished product inventory acquired or produced in previous quarters was sold in the fourth quarter of 2007.

The Redwater West business line purchases an NGL mix from various producers and fractionates it into finished products at the Redwater fractionation facility near Edmonton, Alberta. Because the feedstock for this business line is primarily NGL mix rather than natural gas, the frac spread ratio has a smaller impact on margin than in the Empress East business line. In the fourth quarter of 2007, the margin for this business line was $41.7 million (2006 - $30.3 million). The increase in margin is primarily due to increased propane-plus sales volumes accompanied with an approximate 30 percent increase in propane-plus prices in the quarter.

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 2007, the margin for this business line was $19.6 million (2006 - $13.2 million). The increase in the margin is due to increased revenue associated with the condensate loading/offloading facility at Redwater.

Operations - Midstream NGL sales volumes

Midstream sold 135,981 bpd in the fourth quarter of 2007, up 18 percent when compared with the fourth quarter of 2006.

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

Fourth quarter 2007 EBITDA of $89.4 million increased $15.0 million or 20 percent from $74.4 million in the fourth quarter of 2006. A $65.1 million increase in gross operating margin as described above was partially offset by a $44.0 million increase in realized losses on financial derivative instruments, when compared with the fourth quarter of 2006. The increased cost associated with the financial derivative instruments is more than offset by the realized product margin in the quarter. Funds flow from operations for the fourth quarter of 2007 was $77.1 million, an increase of $16.6 million or 27 percent above the $60.5 million for the fourth quarter 2006. The increase in funds flow from operations reflects the higher EBITDA.

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

Capital expenditures

Midstream capital expenditures for the fourth quarter of 2007 totaled $22.7 million. In the quarter, $1.4 million was spent on a new condensate offloading and terminalling facility, expansion to the recently completed truck loading facilities, and continued development of cavern storage. In addition, $13.9 million was added to capitalized line-fill, $2.4 million was spent on sustaining capital requirements and $5.0 million was spent on office furniture and equipment related to the new office space to be occupied in 2008.

2007 Year end results



Consolidated funds flow from operations and cash distributions

Consolidated Year ended December 31,
----------------------------------------------------------------------------
($ 000s, except per unit data) 2007 2006 % Change
----------------------------------------------------------------------------
----------------------------------------------------------------------------

Revenue, Funds Flow from Operations and
Distributions
Revenue (net of royalties and financial
derivative instruments) $ 2,167,276 $ 2,187,253 (1)
----------------------------------------------------------------------------
Funds flow from operations $ 468,255 $ 432,664 8
Per weighted average unit - basic and
diluted (1) $ 2.04 $ 2.20 (7)
Declared distributions $ 333,352 $ 283,465 18
Per Unit 1.44 1.44 -
Percent of funds flow from operations
distributed (2) 77% 67% 15
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(1) Includes dilutive impact of unit options, exchangeable shares and
convertible debentures.
(2) Calculated as declared distributions to unitholders divided by funds
flow from operations less distributions to non-controlling interests
of $35.8 million (2006 - $6.5 million).


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

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

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

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

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

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

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

Outlook

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

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

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

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

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

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

Distributions

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



Distribution
Record Date Payment Date (Cdn$) (US$)(i)
----------------------------------------------------------------------------
2007
January 22, 2007 February 15, 2007 $ 0.12 0.10
February 28, 2007 March 15, 2007 0.12 0.10
March 22, 2007 April 13, 2007 0.12 0.11
April 24, 2007 May 15, 2007 0.12 0.11
May 18, 2007 June 15, 2007 0.12 0.11
June 22, 2007 July 13, 2007 0.12 0.11
July 23, 2007 August 15, 2007 0.12 0.11
August 22, 2007 September 14, 2007 0.12 0.12
September 24, 2007 October 15, 2007 0.12 0.12
October 22, 2007 November 15, 2007 0.12 0.12
November 21, 2007 December 14, 2007 0.12 0.12
December 21, 2007 January 15, 2008 0.12 0.12
----------------------------------------------------------------------------
2007 Cash Distributions
paid as declared $ 1.44 1.35
----------------------------------------------------------------------------
----------------------------------------------------------------------------
2006 Cash Distributions paid as
declared 1.44 1.26
2005 Cash Distributions paid as
declared 1.44 1.20
2004 Cash Distributions paid as
declared 1.44 1.10
2003 Cash Distributions paid as
declared 2.06 1.47
2002 Cash Distributions paid as
declared 2.03 1.29
2001 Cash Distributions paid as
declared
- March 2001 - December 2001 2.54 1.64
----------------------------------------------------------------------------
Inception to December 31, 2007 - Distributions paid as
declared $ 12.39 9.31
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(i)Exchange rate based on the Bank of Canada noon rate on the payment date.
The increase in distributions in U.S. dollars in 2007 is due to the
increase in the Canadian dollar relative to the U.S. dollar.


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

Taxation of trust income

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

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

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

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

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

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

- current taxes for midstream operations would occur in 2011.



Net income

Consolidated Year ended December 31,
----------------------------------------------------------------------------
($ 000s, except per unit data) 2007 2006 % Change
----------------------------------------------------------------------------
----------------------------------------------------------------------------

Net income $ 30,434 $ 140,920 (78)
Per weighted average unit
- basic and diluted (1) $ 0.13 $ 0.72 (82)
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(1) Based on weighted average number of trust units outstanding including
the dilutive impact of the unit option plan, exchangeable shares and
convertible debentures.

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

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


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

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

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

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

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

Reconciliation of non-GAAP measure

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



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

Income before taxes and non-controlling
interests $ 35,379 $ 117,496 (70)
----------------------------------------------------------------------------
----------------------------------------------------------------------------

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


Proportionate disclosures

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

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



Year ended December 31,
----------------------------------------------------------------------------
Oil and gas production (boed) 2007 2006
----------------------------------------------------------------------------
COGP 26,509 24,018
----------------------------------------------------------------------------
USOGP (1)
MLP (total) 9,518 1,279
Less: Non-controlling interest (5,454) (434)
----------------------------------------------------------------------------
Provident's interest 4,064 845
----------------------------------------------------------------------------
BreitBurn (total) 2,606 6,442
Less: Non-controlling interest (112) (287)
----------------------------------------------------------------------------
Provident's interest 2,494 6,155
----------------------------------------------------------------------------
Total USOGP - Provident's interest 6,558 7,000
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Total - Provident's interest 33,067 31,018
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(1) In the fourth quarter of 2006, approximately two-thirds of USOGP
production and approximately one-half of USOGP reserves were transferred
from BreitBurn to the MLP as part of the initial public offering of the
MLP.


Funds flow from operations ($ 000's) 2007 2006
----------------------------------------------------------------------------
COGP $ 204,252 $ 185,328
----------------------------------------------------------------------------
Midstream 178,432 184,366
----------------------------------------------------------------------------
----------------------------------------------------------------------------
USOGP (1)
MLP (total) 85,609 12,017
Less: Non-controlling interest (49,118) (4,068)
----------------------------------------------------------------------------
Provident's interest 36,491 7,949
----------------------------------------------------------------------------
BreitBurn (total) 10,821 63,555
Less: Non-controlling interest (438) (2,828)
----------------------------------------------------------------------------
Provident's interest 10,383 60,727
----------------------------------------------------------------------------
Other USOGP (corporate allocations) (10,859) (12,602)
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Total USOGP - Provident's interest 36,015 56,074
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Total - Provident's interest $ 418,699 $ 425,768
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(1) In the fourth quarter of 2006, approximately two-thirds of USOGP
production and approximately one-half of USOGP reserves were transferred
from BreitBurn to the MLP as part of the initial public offering of the
MLP.


Capital expenditures ($ 000's) 2007 2006
----------------------------------------------------------------------------
COGP $ 146,209 $ 70,088
----------------------------------------------------------------------------
Midstream 31,904 66,008
----------------------------------------------------------------------------
----------------------------------------------------------------------------
USOGP (1)
MLP (total) 27,936 2,604
Less: Non-controlling interest (15,392) (883)
----------------------------------------------------------------------------
Provident's interest 12,544 1,721
----------------------------------------------------------------------------
BreitBurn and other (total) 41,073 51,733
Less: Non-controlling interest (1,769) (2,302)
----------------------------------------------------------------------------
Provident's interest 39,304 49,431
----------------------------------------------------------------------------
Total USOGP - Provident's interest 51,848 51,152
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Total - Provident's interest $ 229,961 $187,248
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(1) In the fourth quarter of 2006, approximately two-thirds of USOGP
production and approximately one-half of USOGP reserves were transferred
from BreitBurn to the MLP as part of the initial public offering of the
MLP.


Long-term debt - revolving term credit facilities
($ 000's) 2007 2006
----------------------------------------------------------------------------
COGP (1) $ 230,999 $ 172,980
----------------------------------------------------------------------------
Midstream (1) 692,997 518,941
----------------------------------------------------------------------------
USOGP (2)
MLP (total) 359,712 1,749
Less: Non-controlling interest (280,627) (593)
----------------------------------------------------------------------------
Provident's interest 79,085 1,156
----------------------------------------------------------------------------
BreitBurn (total) 9,124 9,323
Less: Non-controlling interest (363) (415)
----------------------------------------------------------------------------
Provident's interest 8,761 8,908
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Total USOGP - Provident's interest 87,846 10,064
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Total - Provident's interest $ 1,011,842 $ 701,985
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(1) Provident's credit facilities have been allocated for reporting purposes
as 25 percent COGP and 75 percent Midstream.

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


Taxes

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


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

The current and withholding tax expense of $6.4 million in 2007 compares to $5.8 million in 2006. The majority of these taxes arise from Provident's U.S.-based operations. The increase in current taxes was due to U.S.-based Midstream operations.

For the year ended December 31, 2007, future income tax expense was $30.5 million, compared with a recovery of $34.3 million in 2006. The 2007 expense includes $88.4 million relating to the second quarter enactment of legislation to tax publicly traded trusts in 2011.

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

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



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


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



Interest expense

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

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

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

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


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

Financial instruments

Commodity price risk management program

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

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

In 2007 the Midstream segment recorded a realized loss of $79.0 million for NGL inventory price stabilization and frac-spread margin activities. In 2006 the Program recorded a realized loss of $15.4 million for these activities.
Realized gains on foreign exchange contracts related to the Program were $6.3 million. In 2006, the Program recorded a realized gain of $0.4 million for these activities.

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

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

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

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

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

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

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

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

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

Acquisitions

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

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

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

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

Goodwill

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

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



Liquidity and capital resources

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

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

Equity (at book value) 1,708,665 1,542,974 11
----------------------------------------------------------------------------
Total capitalization at book value $ 3,257,937 $ 2,531,759 29
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Total debt as a percentage of total book
value capitalization 48% 39% 23
----------------------------------------------------------------------------
----------------------------------------------------------------------------


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

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



Contractual obligations

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

Long-term debt - revolving
term credit facilities (1) $ 1,483.4 $ 76.1 $ 1,407.3 $ - $ -
Long-term debt - convertible
debentures 343.0 39.1 58.0 245.9 -
Operating lease obligations 224.7 20.4 39.6 34.4 130.3
----------------------------------------------------------------------------
Total $ 2,051.1 $ 135.6 $ 1,504.9 $ 280.3 $130.3
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(1) The terms of the Canadian credit facility have a revolving three year
period expiring on May 30, 2010. Provident can extend the revolving
period by an additional year, no earlier than 90 days and no later than
30 days prior to the end of the first year of the applicable three year
revolving period. If the lenders do not extend the revolving period, or
Provident chooses not to extend, the credit facility will be terminated
and the loan balance will become due and payable in full on the maturity
date. Management intends to extend the revolving period beyond the
current maturity date.


Long-term debt and working capital

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

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

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

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

Trust units

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

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

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

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

Non-controlling interest - USOGP operations

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

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

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



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

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


Capital expenditures and funding

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

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

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


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

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

Non-cash unit based compensation

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



COGP segment review

Crude oil and liquids price

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

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

Realized pricing before financial derivative
instruments
Light/Medium oil $ 60.38 $ 57.18 6
Heavy oil $ 41.85 $ 36.80 14
Natural gas liquids $ 55.07 $ 51.91 6
----------------------------------------------------------------------------
Crude oil and natural gas liquids $ 56.54 $ 52.38 8
----------------------------------------------------------------------------
----------------------------------------------------------------------------


The above realized prices are net of transportation expense.

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



Natural gas price

COGP Year ended December 31,
----------------------------------------------------------------------------
($ per mcf) 2007 2006 % Change
----------------------------------------------------------------------------
AECO monthly index (Cdn$ per mcf) $ 6.59 $ 6.98 (6)
Corporate natural gas price per mcf before
financial derivative instruments (Cdn$) $ 6.42 $ 6.66 (4)
----------------------------------------------------------------------------
----------------------------------------------------------------------------


The above prices are net of transportation expense.

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



Production

COGP Year ended December 31,
----------------------------------------------------------------------------
2007 2006 % Change
----------------------------------------------------------------------------
Daily production
Crude oil - Light/Medium (bpd) 7,876 6,815 16
- Heavy (bpd) 1,921 2,057 (7)
Natural gas liquids (bpd) 1,316 1,401 (6)
Natural gas (mcfd) 92,378 82,469 12
----------------------------------------------------------------------------
Oil equivalent (boed) (1) 26,509 24,018 10
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(1) Provident reports equivalent production converting natural gas to oil
on a 6:1 basis.


For the year ended December 31, 2007, COGP production averaged 26,509 boed, a 10 percent increase compared to 24,018 boed in 2006. The increase is primarily a result of the two recent acquisitions, Capitol on June 19, 2007 and Triwest on December 3, 2007, the full year effect in 2007 of the acquisition of the Rainbow assets (Northwest Alberta) on August 31, 2006, and the production volumes added through drilling and optimization activities, partially offset by natural production declines. The Capitol acquisition became COGP's newest core area, Dixonville, and the Triwest acquisition has been rolled up into the Southeast Saskatchewan core area.

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



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

Year ended December 31,
----------------------------------------------------------------------------
COGP 2007 2006 % Change
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Daily Production - by area (boed) (1)
West Central Alberta 6,997 8,168 (14)
Southern Alberta 5,622 6,237 (10)
Northwest Alberta 4,905 1,545 217
Dixonville (2) 2,058 - -
Southeast Saskatchewan 1,769 1,731 2
Southwest Saskatchewan 1,726 2,624 (34)
Lloydminster 3,418 3,622 (6)
Other 14 91 (85)
----------------------------------------------------------------------------
26,509 24,018 10
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(1) Provident reports equivalent production converting natural gas to oil on
a 6:1 basis.
(2) Represents production from June 19, 2007 (date of Capitol Energy
Resources Ltd. acquisition).


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



Revenue and royalties

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

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

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

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

Total
Revenue $ 445,986 $ 396,981 12
Realized gain on financial derivative
instruments 1,728 4,371 (60)
Royalties (87,046) (81,225) 7
----------------------------------------------------------------------------
Net revenue $ 360,668 $ 320,127 13
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Net revenue (per boe) $ 37.27 $ 36.52 2
Royalties as a percentage of revenue 19.5% 20.5%
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Note: the above revenue, net revenue and net revenue per boe figures are
presented net of transportation expenses.


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

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



Production expenses

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

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


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



Operating netback

COGP Year ended December 31,
----------------------------------------------------------------------------
($ per boe) 2007 2006 % Change
----------------------------------------------------------------------------
Netback per boe
Gross production revenue $ 46.09 $ 45.29 2
Royalties (9.00) (9.27) (3)
Operating costs (11.62) (11.14) 4
----------------------------------------------------------------------------
Field operating netback 25.47 24.88 2
Realized gain on financial derivative
instruments 0.18 0.50 (64)
----------------------------------------------------------------------------
Operating netback after realized financial
derivative instruments $ 25.65 $ 25.38 1
----------------------------------------------------------------------------
----------------------------------------------------------------------------


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

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



General and administrative

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

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

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


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



Capital expenditures

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

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


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

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

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

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



Depletion, depreciation and accretion (DD&A)

COGP Year ended December 31,
----------------------------------------------------------------------------
($ 000s, except per boe data) 2007 2006 % Change
----------------------------------------------------------------------------
DD&A $ 256,723 $ 168,953 52
DD&A (per boe) $ 26.53 $ 19.27 38
----------------------------------------------------------------------------
----------------------------------------------------------------------------


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

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

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

USOGP segment review

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

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

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

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

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



Crude oil, natural gas liquids and natural gas pricing

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

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


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

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



Production

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


Year ended December 31,
----------------------------------------------------------------------------
USOGP 2007 2006 % Change
----------------------------------------------------------------------------
Daily Production - by area (boed) (1)
Los Angeles 4,203 3,901 8
Santa Maria - Or cutt 1,555 1,491 4
Wyoming 2,554 2,329 10
Texas 349 - -
Florida 1,099 - -
Michigan/Indiana/Kentucky 2,364 - -
----------------------------------------------------------------------------
12,124 7,721 57
----------------------------------------------------------------------------
----------------------------------------------------------------------------


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

Revenue and royalties

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



USOGP Year ended December 31,
----------------------------------------------------------------------------
($ 000s, except per boe and mcf amounts) 2007 2006 % Change
----------------------------------------------------------------------------

Oil and natural gas liquids
Revenue $ 222,263 $ 169,322 31
Realized loss on financial
derivative instruments (7,959) (2,505) 218
Royalties (25,294) (16,554) 53
----------------------------------------------------------------------------
Net revenue $ 189,010 $ 150,263 26
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Net revenue (per bbl) $ 55.73 $ 56.26 (1)
Royalties as a percentage of revenue 11.4% 9.8%
----------------------------------------------------------------------------

Natural gas
Revenue $ 38,930 $ 5,820 569
Royalties (6,360) (761) 736
----------------------------------------------------------------------------
Net revenue $ 32,570 $ 5,059 544
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Net revenue (per mcf) $ 6.04 $ 5.72 6
Royalties as a percentage of revenue 16.3% 13.1%
----------------------------------------------------------------------------

Total
Revenue $ 261,193 $ 175,142 49
Realized loss on financial
derivative instruments (7,959) (2,505) 218
Royalties (31,654) (17,315) 83
----------------------------------------------------------------------------
Net revenue $ 221,580 $ 155,322 43
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Net revenue (per boe) $ 51.65 $ 55.12 (6)
Royalties as a percentage of revenue 12.1% 9.9%
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Note: the above revenue, net revenue and net revenue per boe figures are
presented net of transportation expenses. Per boe figures are
calculated using sales volumes, which differ from production volumes
due to changes in inventory levels at the Florida properties,
acquired in the second quarter of 2007.


For the year ended December 31, 2007 revenue was 49 percent higher than the year ended December 31, 2006 primarily due to increases in sales volumes from the acquisitions. Royalties as a percentage of revenue have increased as royalties at the Michigan, Wyoming, Texas and Florida properties are higher than those incurred at the Southern California operations. Net revenue for the year ended December 31, 2007 was 43 percent higher than the year ended December 31, 2006 due to all the acquisitions in 2007 and the higher crude oil and natural gas prices. These increases were partially offset by higher realized losses on financial derivative instruments in 2007 compared to 2006.



Production expenses

USOGP Year ended December 31,
----------------------------------------------------------------------------
($ 000s, except per boe amounts) 2007 2006 % Change
----------------------------------------------------------------------------
Production expenses $ 81,699 $ 52,008 57
Production expenses (per boe) $ 19.04 $ 18.45 3
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Note: Per boe figures are calculated using sales volumes, which differ from
production volumes due to changes in inventory levels at the Florida
properties, acquired in the second quarter of 2007.


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



Operating netback

USOGP Year ended December 31,
----------------------------------------------------------------------------
($ per boe) 2007 2006 % Change
----------------------------------------------------------------------------
USOGP oil equivalent netback per boe
Gross production revenue $ 60.88 $ 62.15 (2)
Royalties (7.38) (6.14) 20
Operating costs (19.04) (18.45) 3
----------------------------------------------------------------------------
Field operating netback $ 34.46 $ 37.56 (8)
Realized loss on financial
derivative instruments (1.85) (0.89) 108
----------------------------------------------------------------------------
Operating netback after realized
financial derivative instruments $ 32.61 $ 36.67 (11)
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Note: Per boe figures are calculated using sales volumes, which differ from
production volumes due to changes in inventory levels at the Florida
properties, acquired in the second quarter of 2007.


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



General and administrative

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

Cash general and administrative
(per boe) $ 10.21 $ 9.41 9
----------------------------------------------------------------------------
----------------------------------------------------------------------------


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

Non-cash unit based compensation for the year ended December 31, 2007 was $6.0 million (2006 - $12.5 million expense). Year-to-date 2007 cash payments related to unit based compensation were $13.9 million compared to $5.0 million in 2006. Payment of unit based compensation is recorded as cash general and administrative expense with an offsetting reduction in non-cash unit based compensation. Excluding this payment, non-cash unit based compensation was $19.9 million for the year ended December 31, 2007 (2006 - $17.5 million). The increase in expense in 2007 reflects higher staffing levels due to the acquisitions as well as strong MLP performance in 2007.



Capital expenditures

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

Property acquisitions, net $ 1,015,803 $ (2,008)
----------------------------------------------------------------------------


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

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



Depletion, depreciation and accretion (DD&A)

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


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

Recent developments

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

Midstream business segment review

The Midstream business

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, Provident holds 18.3 percent ownership of a 300,000 barrel Superior Storage staging facility and 18.3 percent ownership of the 6,600 bpd Superior Depropanizer.

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

- A propane distribution terminal at Lynchburg, Virginia.

- A rail car fleet of approximately 350 rail cars.

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

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

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

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

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

- A rail car fleet of approximately 485 rail cars.

The Commercial Services business line:

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

Long term contracts

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

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.

Also, see commitments disclosure in note 15 to the consolidated financial statements.



2007 Midstream business unit results can be summarized as follows:

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


Gross operating margin

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

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

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

Operations - Midstream NGL sales volumes

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

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

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

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

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

Fractionation spread support program

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

Capital expenditures

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

Foreign ownership

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

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

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

Critical accounting policies

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

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

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

Property, plant and equipment

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

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

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

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

Asset retirement obligation

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

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


Change in accounting policies

Financial instruments and comprehensive income

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

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

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

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

Long-term debt and deferred financing charges

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

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

Statement of comprehensive income

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

Equity

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

Accounting changes

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

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

Business risks

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

- capital markets risk and the ability to finance future growth; 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;

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

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

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

- marketability of oil and natural gas;

- the ability to attract and retain employees; and

- environmental, health and safety risks.

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

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

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

- exposure to commodity price fluctuations;

- the ability to attract and retain employees;

- regulatory intervention in determining processing fees and tariffs; and

- reliance on significant customers.

Provident strives to minimize these business risks by:

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

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

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

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

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

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

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

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

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

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

Unit trading activity

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



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

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

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

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

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

- the emergence of accretive growth opportunities;

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

- the impact of Canadian governmental regulation on the Trust;

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

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

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

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

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

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

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

- currency, exchange and interest rates;

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

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

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

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

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

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

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

- uncertainties associated with estimating reserves;

- royalties payable in respect of oil and gas production;

- interest payable on notes issued in connection with acquisitions;

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

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

- fluctuation in foreign exchange or interest rates;

- stock market volatility and market valuations;

- the impact of environmental events;

- the need to obtain required approvals from regulatory authorities;

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

- failure to realize the anticipated benefits of acquisitions;

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

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

- risks associated with foreign ownership;

- third party performance of obligations under contractual arrangements; and

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

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

- future natural gas and crude oil prices;

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

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

- the impact of increasing competition; and

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

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

- the timely receipt of any required regulatory approvals;

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

- field production rates and decline rates;

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

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

- currency, exchange and interest rates; and

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

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

Additional information

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



Selected annual financial measures

($ 000s except per unit data) 2007 2006 2005
----------------------------------------------------------------------------
Revenue (net of royalties and
financial derivative instruments) $ 2,167,276 $ 2,187,253 $ 1,360,274
Net income 30,434 140,920 96,926
Net income per unit - basic
and diluted 0.13 0.72 0.61
Total assets 5,758,792 3,370,919 2,792,270
Long-term financial liabilities (1) 1,863,512 1,098,040 930,756
Declared distributions per unit. $ 1.44 $ 1.44 $ 1.44
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(1) Includes 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) 2007
----------------------------------------------------------------------------
First Second
Quarter Quarter Third Fourth Year-to-
(1) (1) Quarter Quarter Date
----------------------------------------------------------------------------
Financial - consolidated
Revenue $587,675 $ 504,468 $533,249 $541,884 $2,167,276
Funds flow from
operations $ 87,040 $ 98,503 $105,149 $177,563 $ 468,255
Net income (loss) $ 43,093 $ (46,199) $(35,005) $ 68,545 $ 30,434
Net income (loss) per
unit - basic
and diluted $ 0.20 $ (0.21) $ (0.14) $ 0.28 $ 0.13
Unitholder
distributions $ 76,271 $ 80,236 $ 87,782 $ 89,063 $ 333,352
Distributions per unit $ 0.36 $ 0.36 $ 0.36 $ 0.36 $ 1.44
----------------------------------------------------------------------------

Oil and gas production
Cash revenue $125,777 $ 139,453 $155,541 $186,891 $ 607,662
Earnings before
interest, DD&A, taxes
and other non-cash
items $ 54,736 $ 75,783 $ 82,523 $106,379 $ 319,421
Funds flow from
operations $ 47,636 $ 68,934 $ 72,799 $100,454 $ 289,823
Net (loss) income $ (8,745) $ 95,992 $(26,375) $130,582 $ 191,454
----------------------------------------------------------------------------

Midstream services and
marketing
Cash revenue $453,272 $ 397,713 $433,950 $598,963 $1,883,898
Earnings before
interest, DD&A, taxes
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
Light/medium oil (bpd) 14,071 15,557 19,289 20,721 17,433
Heavy oil (bpd) 1,669 1,918 2,324 1,769 1,921
Natural gas liquids
(bpd) 1,444 1,344 1,281 1,612 1,421
Natural gas (mcfd) 91,432 96,449 95,588 144,678 107,151
Oil equivalent (boed) 32,423 34,893 38,825 48,215 38,633
----------------------------------------------------------------------------

Average selling price net
of transportation
Light/medium oil per
bbl $ 57.21 $ 59.44 $ 64.59 $ 69.70 $ 63.48
(before realized
financial
derivative instruments)
Light/medium oil per
bbl $ 59.93 $ 59.39 $ 61.37 $ 62.34 $ 60.93
(including realized
financial
derivative instruments)
Heavy oil per bbl $ 34.69 $ 42.32 $ 45.34 $ 43.36 $ 41.85
(before realized
financial
derivative instruments)
Heavy oil per bbl $ 34.69 $ 42.32 $ 45.34 $ 43.36 $ 41.85
(including realized
financial
derivative instruments)
Natural gas liquids per
barrel $ 48.86 $ 52.56 $ 55.22 $ 51.39 $ 51.90
Natural gas per mcf $ 7.48 $ 7.25 $ 4.95 $ 6.53 $ 6.53
(before realized
financial
derivative instruments)
Natural gas per mcf $ 7.37 $ 7.18 $ 5.62 $ 6.92 $ 6.78
(including realized
financial
derivative instruments)
----------------------------------------------------------------------------

Midstream
Midstream NGL sales
volumes (bpd) 125,033 109,713 112,386 135,981 120,785
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(1) Restated - see note 3 to third quarter 2007 interim consolidated
financial statements.


Quarterly table

Segmented information by quarter
----------------------------------------------------------------------------
($ 000s except for per
unit and operating amounts) 2006
----------------------------------------------------------------------------
First Second Third Fourth Annual
Quarter Quarter Quarter Quarter Total
----------------------------------------------------------------------------
Financial - consolidated
Revenue $553,706 $424,439 $661,022 $548,086 $2,187,253
Funds flow from
operations $ 78,906 $110,990 $120,089 $122,679 $ 432,664
Net income (loss) $ 24,200 $ 21,371 $120,850 $(25,501) $ 140,920
Net income (loss) per
unit - basic $ 0.13 $ 0.11 $ 0.61 $ (0.12) $ 0.72
Net income (loss) per
unit - diluted $ 0.13 $ 0.11 $ 0.58 $ (0.12) $ 0.72
Unitholder distributions $ 68,350 $ 68,572 $ 70,970 $ 75,573 $ 283,465
Distributions per unit $ 0.36 $ 0.36 $ 0.36 $ 0.36 $ 1.44
----------------------------------------------------------------------------

Oil and gas production
Cash revenue $114,020 $125,744 $116,682 $125,135 $ 481,581
Earnings before interest,
DD&A, taxes $ 64,313 $ 77,698 $ 67,750 $ 66,497 $ 276,258
and other non-cash items
Funds flow from
operations $ 52,813 $ 71,867 $ 61,471 $ 62,147 $ 248,298
Net income (loss) $ 36,484 $ 25,980 $ 38,117 $(14,530) $ 86,051
----------------------------------------------------------------------------

Midstream services and
marketing
Cash revenue $474,515 $367,624 $459,603 $447,244 $1,748,986
Earnings before interest,
DD&A, taxes
and other non-cash items $ 32,813 $ 46,438 $ 65,958 $ 74,422 $ 219,631
Funds flow from
operations $ 26,093 $ 39,123 $ 58,618 $ 60,532 $ 184,366
Net income (loss) $(12,284) $ (4,609) $ 82,733 $(10,971) $ 54,869
----------------------------------------------------------------------------

Operating
Oil and gas production
Light/medium oil (bpd) 14,541 13,923 13,955 13,899 14,114
Heavy oil (bpd) 2,506 2,011 2,004 1,838 2,057
Natural gas liquids
(bpd) 1,527 1,475 1,326 1,345 1,419
Natural gas (mcfd) 78,274 80,084 80,991 100,029 84,891
Oil equivalent (boed) 31,620 30,756 30,784 33,753 31,739
----------------------------------------------------------------------------

Average selling price net
of transportation
Light/medium oil per bbl $ 54.80 $ 69.76 $ 62.95 $ 54.59 $ 60.32
(before realized
financial derivative
instruments)
Light/medium oil per bbl $ 53.40 $ 68.00 $ 60.72 $ 55.56 $ 59.22
(including realized
financial derivative
instruments)
Heavy oil per bbl $ 22.87 $ 50.42 $ 48.15 $ 25.82 $ 36.80
(before realized
financial derivative
instruments)
Heavy oil per bbl $ 22.82 $ 50.42 $ 48.15 $ 25.82 $ 36.78
(including realized
financial derivative
instruments)
Natural gas liquids per
barrel $ 53.91 $ 54.20 $ 52.03 $ 47.49 $ 51.98
Natural gas per mcf $ 8.00 $ 6.10 $ 5.88 $ 6.71 $ 6.66
(before realized
financial derivative
instruments)
Natural gas per mcf $ 7.85 $ 6.41 $ 6.24 $ 7.12 $ 6.91
(including realized
financial derivative
instruments)
----------------------------------------------------------------------------

Midstream
Midstream NGL sales
volumes (bpd) 130,735 100,284 114,839 115,727 115,354
----------------------------------------------------------------------------
----------------------------------------------------------------------------


MANAGEMENT'S REPORT ON INTERNAL CONTROL OVER FINANCIAL REPORTING

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

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

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

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

"signed"

Thomas W. Buchanan

Chief Executive Officer

"signed"

Mark N. Walker

Chief Financial Officer

Calgary, Alberta

March 18, 2008

MANAGEMENT'S RESPONSIBILITY FOR FINANCIAL STATEMENTS

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

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

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

"signed"

Thomas W. Buchanan

Chief Executive Officer

"signed"

Mark N. Walker

Chief Financial Officer

Calgary, Alberta

March 18, 2008

Independent Auditors' Report

To the Unitholders of Provident Energy Trust

We have completed integrated audits of the consolidated financial statements and internal control over financial reporting of Provident Energy Trust (the "Trust") as at December 31, 2007 and 2006. 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, 2007 and December 31, 2006, and the related consolidated statements of operations and accumulated income, comprehensive income and accumulated comprehensive income and cash flows for each of the years then ended. These financial statements are the responsibility of the Trust's management. Our responsibility is to express an opinion on these financial statements based on our audits.

We conducted our audits of the Trust's 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, 2007 and December 31, 2006 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, 2007, 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 effectiveness of the Trust's internal control over financial reporting based on our audit.

We conducted our audit of internal control over financial reporting in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. An audit of internal control over financial reporting includes obtaining an understanding of internal control over financial reporting, 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.

As described in Management's Report on Internal Control Over Financial Reporting, management excluded certain assets acquired from Quicksilver Resources, Inc., ("QRI asset acquisition") from its assessment of the effectiveness of the Trust's internal control over financial reporting because they were acquired by a subsidiary of the Trust in a purchase business combination during 2007. We have also excluded the QRI asset acquisition from our audit of internal control over financial reporting. The total assets and total revenues associated with the QRI asset acquisition represent 26 percent and less than 1 percent respectively, of the related consolidated financial statement amounts as of and for the year ended December 31, 2007.

In our opinion, the Trust maintained, in all material respects, effective internal control over financial reporting as of December 31, 2007 based on criteria established in Internal Control - Integrated Framework issued by the COSO.

PricewaterhouseCoopers LLP

Chartered Accountants

March 18, 2008

Comments by Auditor on Canada - U.S. reporting differences

In the United States, reporting standards for auditors require the addition of an explanatory paragraph (following the opinion paragraph) when there is change in accounting principles that has a material effect on the comparability of the Trust's financial statements, such as the changes described in Note 3 to the Consolidated Financial Statements. Our report is expressed in accordance with Canadian reporting standards which do not require a reference to such a change in accounting principles in the auditors' report when the change is properly accounted for and adequately disclosed in the financial statements.

PricewaterhouseCoopers LLP

Chartered Accountants

March 18, 2008



PROVIDENT ENERGY TRUST
CONSOLIDATED BALANCE SHEETS
Canadian dollars (000s)
As at As at
December 31, December 31,
2007 2006
-------------------------------
-------------------------------
Assets
Current assets
Cash and cash equivalents $ 6,820 $ 10,302
Accounts receivable 417,562 270,135
Petroleum product inventory 90,274 85,868
Prepaid expenses and other current
assets 9,018 16,381
Financial derivative instruments
(note 13) 2,289 12,909
----------------------------------------------------------------------------
525,963 395,595

Investments 21,154 4,320
Deferred financing charges - 12,351
Long-term financial derivative
instruments (note 13) - 171
Property, plant and equipment (note 5) 4,518,820 2,333,537
Intangible assets (note 6) 175,556 193,592
Goodwill (note 4) 517,299 431,353
----------------------------------------------------------------------------
$ 5,758,792 $ 3,370,919
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Liabilities
Current liabilities
Accounts payable and accrued liabilities $ 424,468 $ 295,003
Cash distributions payable 25,100 21,506
Distributions payable to non-controlling
interests - 677
Current portion of convertible
debentures (note 7) 19,198 -
Financial derivative instruments
(note 13) 167,713 22,602
----------------------------------------------------------------------------
636,479 339,788
Long-term debt - revolving term credit
facilities (note 7) 1,292,832 702,993
Long-term debt - convertible
debentures (note 7) 256,440 285,792
Asset retirement obligation (note 8) 80,900 49,614
Long-term financial derivative
instruments (note 13) 212,581 43,336
Other long-term liabilities (note 11) 20,759 16,305
Future income taxes (note 12) 450,000 309,006
Non-controlling interests (note 9)
USOGP operations 1,100,136 81,111

Subsequent event (note 16)

Unitholders' equity
Unitholders' contributions (note 10) 2,750,374 2,254,048
Convertible debentures equity component 18,213 18,522
Contributed surplus (note 11) 801 1,315
Accumulated other comprehensive (loss)
income (69,188) (42,294)
Accumulated income 268,642 238,208
Accumulated cash distributions (1,260,177) (926,825)
----------------------------------------------------------------------------
1,708,665 1,542,974
----------------------------------------------------------------------------
----------------------------------------------------------------------------
$ 5,758,792 $ 3,370,919
----------------------------------------------------------------------------
----------------------------------------------------------------------------

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

On behalf of the Board of Directors:

"signed" "signed"
M.H. (Mike) Shaikh, FCA Thomas W. Buchanan, CA
Director Director


PROVIDENT ENERGY TRUST
CONSOLIDATED STATEMENT OF OPERATIONS AND ACCUMULATED INCOME
Canadian dollars (000s except per unit amounts)
Year ended
December 31,
-------------------------

2007 2006
-------------------------
-------------------------
Revenue
Revenue $ 2,572,265 $ 2,244,107
Realized loss on financial derivative instruments (80,705) (13,540)
Unrealized loss on financial derivative
instruments (324,284) (43,314)
----------------------------------------------------------------------------
2,167,276 2,187,253
Expenses
Cost of goods sold 1,605,782 1,471,171
Production, operating and maintenance 208,180 172,253
Transportation 28,120 19,786
Depletion, depreciation and accretion 351,364 249,139
General and administrative (note 11) 114,973 97,288
Interest on bank debt 51,660 34,666
Interest and accretion on convertible debentures 25,347 23,919
Amortization of deferred financing charges - 3,854
Foreign exchange loss (gain) and other 6,795 (2,319)
Dilution gain (note 9) (260,324) -
----------------------------------------------------------------------------
2,131,897 2,069,757
----------------------------------------------------------------------------

Income before taxes and non-controlling interests 35,379 117,496
----------------------------------------------------------------------------

Capital tax expense 3,762 1,314
Current and withholding tax expense 6,362 5,829
Future income tax expense (recovery) (note 12) 30,487 (34,316)
----------------------------------------------------------------------------
----------------------------------------------------------------------------
40,611 (27,173)
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Net (loss) income before non-controlling interests (5,232) 144,669
----------------------------------------------------------------------------
Non-controlling interests (note 9)
USOGP operations (35,666) 2,995
Exchangeable shares - 754
----------------------------------------------------------------------------
Net income 30,434 140,920
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Accumulated income, beginning of year $ 238,208 $ 97,288
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Accumulated income, end of year $ 268,642 $ 238,208
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Net income per unit -- basic and diluted $ 0.13 $ 0.72
----------------------------------------------------------------------------
----------------------------------------------------------------------------

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


PROVIDENT ENERGY TRUST
CONSOLIDATED STATEMENT OF CASH FLOWS
Canadian Dollars (000s)
Year ended
December 31,
-------------------------
2007 2006
-------------------------

Cash provided by operating activities
Net income for the year $ 30,434 $ 140,920
Add (deduct) non-cash items:
Depletion, depreciation and accretion 351,364 249,139
Non-cash interest expense and other 10,290 6,357
Non-cash unit based compensation (note 11) 14,014 23,083
Unrealized loss on financial derivative
instruments 324,284 43,314
Unrealized foreign exchange loss and other 3,372 418
Future income tax expense (recovery) (note 12) 30,487 (34,316)
Dilution gain (note 9) (260,324) -
Net (loss) income attributable to non-controlling
interests (35,666) 3,749
----------------------------------------------------------------------------
Funds flow from operations 468,255 432,664
----------------------------------------------------------------------------
Site restoration expenditures (note 14) (4,424) (4,622)
Change in non-cash operating working capital 624 (13,693)
----------------------------------------------------------------------------
464,455 414,349
----------------------------------------------------------------------------

Cash provided by financing activities
Increase in long-term debt 534,215 117,385
Declared distributions to unitholders (333,352) (283,465)
Declared distributions to non-controlling
interests (35,846) (6,523)
Issue of trust units, net of issue costs 412,909 257,076
Contributions by non-controlling interests
(note 9) 683,100 135,829
Change in non-cash financing working capital 2,179 (154)
----------------------------------------------------------------------------
1,263,205 220,148
----------------------------------------------------------------------------

Cash used for investing activities
Capital expenditures (247,122) (190,433)
Capitol Energy acquisition (note 4) (467,495) -
Triwest Energy acquisition (note 4) (2,300) -
USOGP natural gas asset acquisition (note 4) (763,652) -
Acquisition of Midstream NGL business - (1,036)
Oil and gas property acquisitions, net (note 4) (265,201) (481,625)
Increase in investments (5,450) -
Proceeds on sale of assets 5,030 11,517
Change in reserve for future site reclamation
(note 14) - 1,872
Change in non-cash investing working capital 15,048 3,397
----------------------------------------------------------------------------
(1,731,142) (656,308)
----------------------------------------------------------------------------

Decrease in cash and cash equivalents (3,482) (21,811)
Cash and cash equivalents beginning of year 10,302 32,113
----------------------------------------------------------------------------
Cash and cash equivalents end of year $ 6,820 $ 10,302
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Supplemental disclosure of cash flow information
Cash interest paid including debenture interest $ 69,600 $ 56,036
Cash taxes paid $ 13,741 $ 9,601
----------------------------------------------------------------------------
----------------------------------------------------------------------------

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


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

Net income $ 30,434 $ 140,920
----------------------------------------------------------------------------

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

Comprehensive income $ 3,540 $ 140,411
----------------------------------------------------------------------------
----------------------------------------------------------------------------

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

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


NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

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

December 31, 2007

1. Structure of the Trust

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

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

2. Significant accounting policies

i) Principles of consolidation and investments

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

ii) Financial instruments

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

iii) Cash and cash equivalents

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

iv) Property, plant & equipment and intangible assets

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

a) Depletion, depreciation and accretion

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

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

b) Impairment

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

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

v) Joint venture

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

vi) Inventory

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

vii) Goodwill

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

viii) Asset retirement obligation

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

ix) Unit based compensation

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

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

x) Trust unit calculations

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

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

xi) Income taxes

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

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

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

xii) Revenue recognition

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

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

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

xiii) Foreign currency translation

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

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

xiv) Use of estimates

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

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

3. Changes in accounting policies and practices

A. Changes in accounting policies

i) Financial instruments

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

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

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

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

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

Long-term debt and deferred financing charges

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

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

Comprehensive income

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

ii) Equity

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

iii) Accounting changes

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

B. Recent accounting pronouncements

i) Inventory

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

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

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

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

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

ii) Capital disclosures

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

iii) Goodwill and intangible assets

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

4. Acquisitions

i) Acquisition of Triwest

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



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


ii) Acquisition of USOGP natural gas assets

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

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



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


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

iii) Acquisition of Capitol

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



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


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

iv) MLP acquisitions

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



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


The acquisitions were financed by the issue of units by the MLP to institutional investors (see note 9).

v) Acquisition of Rainbow assets

On August 31, 2006 Provident acquired a package of natural gas producing assets in the Rainbow and Peace River Arch areas of northwestern Alberta. The transaction was accounted for as an asset purchase with the allocation of the purchase price as follows:




Net assets acquired and liabilities assumed
Property, plant and equipment $ 660,427
Asset retirement obligation (1,903)
Future income taxes (185,726)
---------------------------------------------------------------------------
$ 472,798
---------------------------------------------------------------------------
Consideration
Acquisition costs $ 500
Cash 472,298
---------------------------------------------------------------------------
$ 472,798
---------------------------------------------------------------------------
---------------------------------------------------------------------------


The acquisition was financed by the issuance of 16,325,000 units at $13.85
per unit and Provident's credit facilities.


5. Property, plant and equipment

Accumulated
depletion and Net Book
Year ended December 31, 2007 Cost depreciation Value
---------------------------------------------------------------------------
Oil and natural gas properties $ 4,977,958 $ 1,215,499 $ 3,762,459
Midstream assets 790,434 63,763 726,671
Office equipment 40,936 11,246 29,690
---------------------------------------------------------------------------
Total $ 5,809,328 $ 1,290,508 $ 4,518,820
---------------------------------------------------------------------------
---------------------------------------------------------------------------

Accumulated
depletion and Net Book
Year ended December 31, 2006 Cost depreciation value
---------------------------------------------------------------------------

Oil and natural gas properties $ 2,513,031 $ 927,087 $ 1,585,944
Midstream assets 781,092 42,143 738,949
Office equipment 17,070 8,426 8,644
---------------------------------------------------------------------------
Total $ 3,311,193 $ 977,656 $ 2,333,537
---------------------------------------------------------------------------
---------------------------------------------------------------------------


Costs associated with unproved properties and major development projects excluded from costs subject to depletion as at December 31, 2007 totaled $137.7 million (December 31, 2006 - $17.8 million). Midstream assets include $35.9 million (2006 - $22.0 million) for products required for line-fill and cavern bottoms.

An impairment test calculation was performed on property, plant and equipment at December 31, 2007 in which the estimated undiscounted future net cash flows based on estimated future prices associated with the proved reserves exceeded the carrying amount of oil and gas property, plant and equipment for each cost centre.

The following table outlines prices used in the impairment test at December 31, 2007:



Oil Gas NGL
Year $/bbl $/mcf $/bbl
-------------------------------------------------------------------
2008 $ 60.10 $ 6.80 $ 63.71
2009 $ 59.38 $ 7.60 $ 62.00
2010 $ 59.24 $ 7.87 $ 60.98
2011 $ 58.11 $ 8.11 $ 59.39
2012 $ 58.55 $ 8.37 $ 59.91
Thereafter (1) 2.00% 2.00% 2.00%
-------------------------------------------------------------------
-------------------------------------------------------------------
(1) Percentage change represents the increase in each year after
2012 to the end of the reserve life.


6. Intangible assets
Accumulated Net Book
December 31, 2007 Cost amortization value
---------------------------------------------------------------------------
Midstream contracts and
customer relationships $ 183,100 $ 25,049 $ 158,051
Fractionation spread support
agreement - Midstream 17,600 17,600 -
Other intangible
assets - Midstream 16,308 2,566 13,742
U.S. oil and natural gas production
related intangible assets 8,468 4,705 3,763
---------------------------------------------------------------------------
Total $ 225,476 $ 49,920 $ 175,556
---------------------------------------------------------------------------
---------------------------------------------------------------------------

Accumulated Net Book
December 31, 2006 Cost amortization value
---------------------------------------------------------------------------
Midstream contracts and customer
relationships $ 183,100 $ 12,842 $ 170,258
Fractionation spread support
agreement - Midstream 17,600 9,258 8,342
Other intangible
assets - Midstream 16,308 1,316 14,992
---------------------------------------------------------------------------
Total $ 217,008 $ 23,416 $ 193,592
---------------------------------------------------------------------------
---------------------------------------------------------------------------



7. Long-term debt
December 31, 2007 December 31, 2006
---------------------------------------------------------------------------
Revolving term credit facilities $ 1,292,832 $ 702,993
---------------------------------------------------------------------------
Convertible debentures 275,638 285,792
Current portion of convertible
debentures (19,198) -
---------------------------------------------------------------------------
256,440 285,792
---------------------------------------------------------------------------
Total $ 1,549,272 $ 988,785
---------------------------------------------------------------------------
---------------------------------------------------------------------------


i) Revolving term credit facilities

Provident has a $1,125 million term credit facility with a syndicate of Canadian chartered banks secured by midstream assets and by its Canadian oil and gas properties. Provident may draw on the credit facility by way of Canadian prime rate loans, U.S. base rate loans, banker's acceptances, letters of credit or LIBOR loans. At December 31, 2006 the facility totaled $925 million. In May 2007 the facility was increased to its current level of $1,125 million. At December 31, 2007, $925.3 million was drawn on this facility. Included in the carrying value at December 31, 2007 were financing costs of $1.3 million.

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

In addition, Provident's U.S. subsidiaries have credit facilities with a borrowing base of U.S. $737.7 million with a syndicate of U.S. banks secured by oil and gas assets of the subsidiaries. Provident's U.S. subsidiaries may draw upon the facility by way of U.S. base rate loans, LIBOR loans or letters of credit. The facilities have a termination date of October 10, 2010. At December 31, 2007, $375.4 million was drawn on these facilities. Included in the carrying value at December 31, 2007 were financing costs of $6.6 million.

At December 31, 2007 the effective interest rate of the outstanding credit facilities was 5.9 percent (2006 - 5.2 percent). At December 31, 2007 Provident had $35.9 million in letters of credit outstanding (2006 - $31.9 million) that guarantee Provident's performance under certain commercial and other contracts.

ii) Convertible debentures

The Trust may elect to satisfy interest and principal obligations by the issue of trust units. For the twelve months ended December 31, 2007, $6.1 million of the face value of debentures were converted to trust units at the election of debenture holders (2006 - $15.4 million). Included in the carrying value at December 31, 2007 were financing costs of $7.0 million. The fair value of the convertible debentures at December 31, 2007 approximates the face value of the instruments. The following table details each outstanding convertible debenture.



As at As at
December 31, December 31,
Convertible Debentures 2007 2006
---------------------------------------------------------------------------
Conversion
($ 000s except Price
conversion Carrying Face Carrying Face Maturity per
pricing) Value (1) Value Value (1) Value Date unit(2)
---------------------------------------------------------------------------
6.5% Convertible April 30,
Debentures $ 140,515 $ 149,980 $ 142,860 $ 150,000 2011 14.75
6.5% Convertible Aug. 31,
Debentures 91,460 99,024 93,134 99,024 2012 13.75
8.0% Convertible July 31,
Debentures 24,465 25,109 24,402 25,114 2009 12.00
8.75% Convertible Dec. 31,
Debentures 19,198 19,931 25,396 25,972 2008 11.05
---------------------------------------------------------------------------
$ 275,638 $ 294,044 $ 285,792 $ 300,110
---------------------------------------------------------------------------
---------------------------------------------------------------------------
(1) Excluding equity component of convertible debentures
(2) The debentures may be converted into trust units at the option of the
holder of the debenture at the conversion price per unit


8. Asset retirement obligation

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

The total undiscounted amount of future cash flows required to settle asset retirement obligations related to oil and gas operations is estimated to be $613.1 million (2006 - $411.6 million). Payments to settle oil and gas asset retirement obligations occur over the operating lives of the assets estimated to be from two to 52 years.

The total undiscounted amount of future cash flows required to settle the midstream asset retirement obligations is estimated to be $166.1 million (2006 - $166.1 million). The estimated costs include such activities as dismantling, demolition and disposal of the facilities as well as remediation and restoration of the surface land. Payments to settle the midstream asset retirement obligations are expected to occur subsequent to the closure of the facilities and related assets. Settlement of these obligations is expected to occur in 29 to 40 years.



Year ended December 31,
---------------------------------------------------------------------------
($000s) 2007 2006
---------------------------------------------------------------------------
Carrying amount, beginning of year $ 49,614 $ 41,133
Acquisitions 17,442 1,903
Change in estimate 14,561 6,793
Increase in liabilities incurred during the year 2,547 1,443
Settlement of liabilities during the year (4,424) (4,622)
Decrease in liabilities due to disposition (654) (946)
Accretion of liability 4,885 3,822
Foreign currency translation adjustments (3,071) 88
---------------------------------------------------------------------------
Carrying amount, end of year $ 80,900 $ 49,614
---------------------------------------------------------------------------
---------------------------------------------------------------------------



9. Non-controlling interests - USOGP

Year ended December 31,
---------------------------------------------------------------------------
2007 2006
---------------------------------------------------------------------------
Non-controlling interests, beginning of year $ 81,111 $ 11,885
Net (loss) income attributable to
non-controlling interests (35,666) 2,995
Distributions to non-controlling interests (35,846) (6,523)
Investments by non-controlling interests 1,129,073 72,754
Foreign currency translation adjustment (38,536) -
---------------------------------------------------------------------------
Non-controlling interests, end of year $ 1,100,136 $ 81,111
---------------------------------------------------------------------------
Accumulated (loss) income attributable to
non-controlling interests $ (30,152) $ 5,514
---------------------------------------------------------------------------
---------------------------------------------------------------------------


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

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

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

10. Unitholders' contributions

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

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

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

i) 2007 activity

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

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

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

ii) 2006 activity

On July 31, 2006 the Trust issued 16,325,000 Subscription Receipts at a price of $13.85 per Subscription Receipt for total proceeds of $226.1 million ($214.2 million net of issue costs). Each Subscription Receipt entitled the holder to receive one trust unit upon completion of the Rainbow asset acquisition. The acquisition closed on August 31, 2006 at which time all the outstanding Subscription Receipts were converted into trust units. At that time, the holders of the Subscription Receipts were also entitled to $0.12 per trust unit, which is the equivalent of the August distribution paid in September. This payment was treated as a reduction to the proceeds received for the units issued through the Subscription Receipts to $13.73 per trust unit, reducing the amount attributed to Unitholders' contributions by $2.0 million. Proceeds from the issue were used to fund the Rainbow asset acquisition.

In 2006, the Trust issued 6.1 million units related to Provident's DRIP program, conversion of exchangeable shares to units, conversion of convertible debentures to units and units issued pursuant to Provident's Unit Option Plan. The net increase in unitholders' contributions associated with these activities was $70.1 million.



Year ended December 31,
---------------------------------------------------------------------------
2007 2006
---------------------------------------------------------------------------
Number Amount Number Amount
Trust Units of units (000s) of units (000s)
---------------------------------------------------------------------------
Balance at beginning
of year 211,228,407 $ 2,254,048 188,772,788 $ 1,971,707
Issued for cash 29,313,727 373,750 16,325,000 224,142
Issued to acquire
Triwest Energy Inc. 6,251,149 76,577 - -
Exchangeable share
conversions - - 881,083 9,012
Issued pursuant to
unit option plan 825,349 8,426 907,201 8,589
Issued pursuant to
the distribution
reinvestment plan 3,941,864 45,338 2,714,636 33,045
To be issued pursuant
to the distribution
reinvestment plan 525,822 5,153 300,134 3,806
Debenture conversions 548,455 6,270 1,327,565 15,689
Unit issue costs - (19,188) - (11,942)
---------------------------------------------------------------------------
Balance at end of year 252,634,773 $ 2,750,374 211,228,407 $ 2,254,048
---------------------------------------------------------------------------
---------------------------------------------------------------------------


The basic per trust unit amounts for 2007 were calculated based on the weighted average number of units outstanding of 229,939,158 (2006 - 196,627,060). The diluted per trust unit amounts for 2007 are calculated including no additional trust units (2006 - 286,957) for the dilutive effect of the unit option plan and the convertible debentures.

11. Unit based compensation

i) Restricted/Performance units

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

As of December 31, 2007 there were 1,408,196 RTUs and 4,441,152 PTUs outstanding (2006 - 571,423 RTUs and 1,704,234 PTUs). The fair value estimate associated with the RTUs and PTUs is expensed in the statement of operations over the vesting period. At December 31, 2007, $12.7 million (2006 - $2.3 million) is included in accounts payable and accrued liabilities for this plan and $14.8 million (2006 - $13.3 million) is included in other long-term liabilities. The following table reconciles the expense recorded for RTUs and PTUs.



Year ended December 31,
---------------------------------------------------------------------------
2007 2006
---------------------------------------------------------------------------
Cash general and administrative $ 2,395 $ 1,021
Non- cash unit based compensation (included
in general and administrative) 11,576 11,156
Production, operating and maintenance expense 1,247 939
---------------------------------------------------------------------------
$ 15,218 $ 13,116
---------------------------------------------------------------------------
---------------------------------------------------------------------------


ii) Unit option plan

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

At December 31, 2007, the Trust had 1,279,169 options outstanding and exercisable with strike prices ranging between $10.49 and $12.14 per unit. The weighted average remaining contractual life of the options was 0.87 years and the weighted average exercise price was $11.04 per unit excluding average potential reductions to the strike prices of $1.77 per unit.

At December 31, 2006, the Trust had 2,114,808 options outstanding with strike prices ranging between $10.49 and $12.14 per unit. The weighted average remaining contractual life of the options was 1.96 years and the weighted average exercise price was $11.09 per unit excluding average potential reductions to the strike prices of $1.50 per unit. Of these outstanding options, 1,947,989 were exercisable with a weighted average price of $11.08.

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



Year ended December 31,
---------------------------------------------------------------------------
2007 2006
---------------------------------------------------------------------------
Contributed surplus, beginning of the year $ 1,315 $ 1,675
Non-cash unit based compensation (included
in general and administrative) 57 203
Benefit on options exercised charged
to unitholders' equity (571) (563)
---------------------------------------------------------------------------
Contributed surplus, end of year $ 801 $ 1,315
---------------------------------------------------------------------------
---------------------------------------------------------------------------


iii) Unit appreciation rights

At December 31, 2007, the Trust's U.S. subsidiaries had unit appreciation rights (UARs) outstanding of 187,656 (2006 - 472,521) with a weighted average price of U.S. $9.58 (2006 - U.S. $8.41). Of these outstanding UARs, 148,336 (2006 - 81,852) were exercisable at a weighted average price of U.S. $9.46 (2006 - U.S. $8.46).

The fair value associated with the UARs is expensed in the statement of operations over the vesting period. At December 31, 2007, $0.8 million (2006 - $2.5 million) is included in accounts payable and accrued liabilities for this plan and nil (2006 - $0.1 million) is included in other long-term liabilities. The following table reconciles the expense recorded for UARs.



Year ended December 31,
---------------------------------------------------------------------------
2007 2006
---------------------------------------------------------------------------
Cash general and administrative $ 2,113 $ 798
Non-cash unit based compensation (included
in general and administrative) (1,490) 1,246
---------------------------------------------------------------------------
$ 623 $ 2,044
---------------------------------------------------------------------------
---------------------------------------------------------------------------


iv) Other unit based compensation

Pursuant to employment agreements between the Trust's U.S. subsidiaries and certain employees, the employees are eligible to receive cash compensation in relation to the value of a specified number of underlying notional units. The value of each notional unit is determined on the basis of a valuation of the U.S. subsidiaries as at the end of the fiscal period. At December 31, 2007 there were 3,061,137 notional units outstanding under the key employee plan (2006 - 2,755,566). There were 2,965,502 notional units outstanding under other USOGP unit based plans (2006 - 12,984,001). At December 31, 2007, $8.7 million (2006 - $13.4 million) is included in accounts payable and accrued liabilities for these plans, and $6.0 million (2006 - $2.9 million) is included in other long-term liabilities.

The following table reconciles the expense recorded for the other unit based compensation plans.



Year ended December 31,
---------------------------------------------------------------------------
2007 2006
---------------------------------------------------------------------------
Cash general and administrative $ 11,189 $ 3,807
Non-cash unit based compensation (included
in general and administrative) 3,871 10,478
---------------------------------------------------------------------------
$ 15,060 $ 14,285
---------------------------------------------------------------------------
---------------------------------------------------------------------------


12. Income taxes

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

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

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

Provident follows the liability method for calculating future income taxes. Under this method, future income tax assets and liabilities are recognized based on the estimated tax effects of temporary differences in the carrying value of assets and liabilities and their respective tax bases, using income tax rates substantively enacted on the consolidated balance sheet date:



Year ended December 31,
---------------------------------------------------------------------------
Future income taxes 2007 2006
---------------------------------------------------------------------------
Petroleum and natural gas properties,
production facilities and other $ 332,301 $ 266,156
Midstream facilities 117,699 42,850
---------------------------------------------------------------------------
$ 450,000 $ 309,006
---------------------------------------------------------------------------
---------------------------------------------------------------------------


The income tax provision differs from the expected amount calculated by applying the Canadian combined federal and provincial income tax rate of 32.81 percent (2006 - 34.67 percent) as follows:



Year ended December 31,
---------------------------------------------------------------------------
2007 2006
---------------------------------------------------------------------------
Expected income tax expense $ 23,310 $ 40,736
Increase (decrease) resulting from:
Future income tax expense relating to enactment
of Bill C-52, Budget Implementation Act 2007 88,352 -
Non-deductible Crown charges and other payments - 8,135
Federal resource allowance - (5,742)
Alberta Royalty Tax Credit - (173)
Income of the Trust and other (73,045) (70,999)
Capital Taxes 3,762 1,314
Witholding tax and other 3,425 3,308
Income tax rate changes (5,193) (3,752)
---------------------------------------------------------------------------
Income tax expense (recovery) $ 40,611 $ (27,173)
---------------------------------------------------------------------------
---------------------------------------------------------------------------


13. Financial instruments

Financial instruments of the Trust carried on the consolidated balance sheet consist mainly of cash and cash equivalents, accounts receivable, current liabilities, commodity, foreign currency and interest rate contracts and long-term debt. Except as disclosed in note 7, as at December 31, 2007 and 2006, there were no significant differences between the carrying value of these financial instruments and their estimated fair value.

Substantially all of the Trust's accounts receivable are due from customers and joint venture partners in the oil and gas and midstream services and marketing industries and are subject to credit risk. The Trust partially mitigates associated credit risk by limiting transactions with certain counterparties to limits imposed by the Trust based on the Trust's assessment of the creditworthiness of such counterparties. The carrying value of accounts receivable reflects management's assessment of the associated credit risks. With respect to counterparties to financial instruments, the Trust partially mitigates associated credit risk by limiting transactions to counterparties with investment grade credit ratings and obtaining financial guarantees from certain counterparties.

Provident's commodity price risk management program is intended to minimize the volatility of commodity prices and to assist with stabilizing cash flow and distributions. Provident seeks to accomplish this through the use of financial instruments from time to time to reduce its exposure to fluctuations in commodity prices and foreign exchange rates.

With respect to financial instruments, Provident could be exposed to losses if a counterparty fails to perform in accordance with the terms of the contract. This risk is managed by diversifying the derivative portfolio among counterparties meeting certain financial criteria.

i) Commodity price

a) Crude oil

In 2007, Provident paid $17.6 million (2006 - $5.7 million) to settle various oil market based contracts on an aggregate volume of 3.4 million barrels (2006 - 2.1 million barrels). The estimated value of contracts in place if settled at market prices at December 31, 2007 would have resulted in an opportunity cost of $98.2 million (2006 - $7.2 million gain).

b) Natural Gas

In 2007, Provident received $9.6 million (2006 - $7.6 million) to settle various natural gas market based contracts on an aggregate of 16.7 million gigajoules ("gj") (2006 - 9.5 million gj's). The estimated value of contracts in place if settled at market prices at December 31, 2007 would have resulted in an opportunity cost of $18.0 million (2006 - $8.6 million gain).

c) Midstream

In 2007, Provident received $17.9 million (2006 - paid $0.6 million) to settle Midstream oil market based contracts on an aggregate volume of 1.2 million barrels (2006 - 1.5 million barrels) and paid $48.7 million (2006 - $27.1 million) to settle Midstream natural gas market based contracts on an aggregate volume of 25.3 million gj's (2006 - 15.3 million gj's). In addition, Provident paid $48.2 million (2006 - received $12.3 million) to settle Midstream NGL market based contracts on an aggregate volume of 7.2 million barrels (2006 - 2.5 million barrels). The estimated value of contracts in place if settled at market prices at December 31, 2007 would have resulted in an opportunity cost of $261.6 million (2006 - $68.8 million).

ii) Foreign exchange contracts

In 2007, Provident received $6.3 million to settle various foreign exchange based contracts (2006 - $0.4 million). The estimated value of contracts in place if settled at foreign exchange rates at December 31, 2007 would have resulted in an opportunity cost of $0.1 million (2006 - $0.1 million gain).

iii) Interest rate contracts

As at December 31, 2007 the estimated value of contracts in place settled at December 31 interest rates was an opportunity cost of $0.1 million (December 31, 2006 - nil).

The contracts in place at December 31, 2007 are summarized in the following tables:



COGP

Year Volume
Product (Buy)Sell Terms Effective Period
---------------------------------------------------------------------------
2008
Crude
Oil 250 Bpd Puts US $63.75 per bbl January 1 - December 31
150 Bpd Puts US $75.00 per bbl January 1 - December 31
1,000 Bpd Puts US $67.50 per bbl January 1 - December 31
250 Bpd Participating Swap US $60.00 per bbl January 1 -
(max to 75.3% above the floor price) December 31
375 Bpd Participating Swap US $65.00 per bbl January 1 -
(52.7% above the floor price) December 31
450 Bpd Participating Swap US $62.50 per bbl January 1 -
(max to 52.5% above the floor price) June 30
450 Bpd Participating Swap US $62.50 per bbl January 1 -
(67.8% above the floor price) June 30
850 Bpd Participating Swap US $65.00 per bbl January 1 -
(57.5% above the floor price) June 30
850 Bpd Participating Swap US $62.50 per bbl January 1 -
(max to 69.9% above the floor price) June 30
300 Bpd Participating Swap US $62.50 per bbl July 1 -
(max to 51% above the floor price) December 31
625 Bpd Participating Swap US $65.00 per bbl July 1 -
(54.25% above the floor price) December 31
925 Bpd Participating Swap US $62.50 per bbl July 1 -
(66% above the floor price) December 31
325 Bpd Participating Swap US $67.20 per bbl July 1 -
(70% above the floor price) December 31
Natural
Gas 1,000 Gjpd Puts Cdn $6.00 per gj January - March 31
5,000 Gjpd Participating Swap Cdn $6.48 per gj January -
(max to 100% above the floor price) March 31
4,000 Gjpd Participating Swap Cdn $7.00 per gj January -
(52.8% above the floor price) March 31
2,000 Gjpd Participating Swap Cdn $7.00 per gj January -
(max to 70% above the floor price) March 31
4,000 Gjpd Participating Swap Cdn $7.25 per gj January -
(56% above the floor price) March 31
8,000 Gjpd Participating Swap Cdn $7.50 per gj January -
(70% above the floor price) March 31
8,000 Gjpd Participating Swap Cdn $7.75 per gj January -
(70% above the floor price) March 31
2,000 Gjpd Participating Swap Cdn $8.00 per gj January -
(max to 75.5% above the floor price) March 31
300 Gjpd Participating Swap Cdn $7.60 per gj January 1 -
(53.5% above the floor price) June 30
2,000 Gjpd Participating Swap Cdn $6.00 per gj January 1 -
(max up to 85% above the floor price) October 31
2,000 Gjpd Participating Swap Cdn $7.50 per gj January 1 -
(max to 25% above the floor price) October 31
900 Gjpd Participating Swap Cdn $7.60 per gj January 1 -
(41% above the floor price) October 31
2,000 Gjpd Participating Swap Cdn $6.00 per gj April 1 -
(56% above the floor price) October 31
2,000 Gjpd Participating Swap Cdn $7.00 per gj April 1 -
(48.6% above the floor price) October 31
1,000 Gjpd Participating Swap Cdn $6.75 per gj April 1 -
(51% above the floor price) December 31
1,000 Gjpd Participating Swap Cdn $7.00 per gj April 1 -
(max up to 85% above the floor price) December 31
1,000 Gjpd Participating Swap Cdn $7.50 per gj April 1 -
(max to 23.5% above the floor price) December 31
1,000 Gjpd Participating Swap Cdn $6.50 per gj November 1 -
(50% above the floor price) December 31
1,000 Gjpd Participating Swap Cdn $6.50 per gj November 1 -
(max up to 90% above the floor price) December 31
2,000 Gjpd Participating Swap Cdn $6.75 per gj November 1 -
(max up to 90% above the floor price) December 31
2,000 Gjpd Participating Swap Cdn $7.00 per gj November 1 -
(max up to 85% above the floor price) December 31
2,000 Gjpd Participating Swap Cdn $7.50 per gj November 1 -
(max up to 100% above the floor price) December 31
400 Gjpd Participating Swap Cdn $7.75 per gj November 1 -
(23% above the floor price) December 31
2009
Crude
Oil 125 Bpd Participating Swap US $60.00 per bbl January 1 -
(60% above the floor price) December 31
825 Bpd Participating Swap US $62.50 per bbl January 1 -
(59.5% above the floor price) December 31
400 Bpd Participating Swap US $62.50 per bbl January 1 -
(max to 50% above the floor price) June 30
1,500 Bpd Participating Swap US $62.50 per bbl January 1 -
(62.6% above the floor price) June 30
775 Bpd Participating Swap US $62.50 per bbl July 1 -
(60.4% above the floor price) December 31
Natural
Gas 400 Gjpd Participating Swap Cdn $7.75 per gj January 1 -
(23% above the floor price) December 31
1,000 Gjpd Participating Swap Cdn $6.50 per gj January 1 -
(50% above the floor price) March 31
1,000 Gjpd Participating Swap Cdn $6.50 per gj January 1 -
(max up to 90% above the floor price) March 31
1,000 Gjpd Participating Swap Cdn $6.75 per gj January 1 -
(51% above the floor price) March 31
2,000 Gjpd Participating Swap Cdn $6.75 per gj January 1 -
(max up to 90% above the floor price) March 31
1,000 Gjpd Participating Swap Cdn $7.00 per gj January 1 -
(max up to 85% above the floor price) March 31
2,000 Gjpd Participating Swap Cdn $7.00 per gj January 1 -
(max up to 85% above the floor price) March 31
3,000 Gjpd Participating Swap Cdn $7.50 per gj January 1 -
(max to 62% above the floor price) March 31
---------------------------------------------------------------------------
---------------------------------------------------------------------------

USOGP

Year Volume
Product (Buy)Sell Terms Effective Period
---------------------------------------------------------------------------
2008
Crude
Oil 125-325 Bpd US $59.25 per bbl January 1 - December 31
325 Bpd US $70.37 per bbl January 1 - December 31
790 Bpd US $72.89 per bbl January 1 - December 31
425 Bpd Participating Swap US $60.00 per bbl January 1 -
(max to 76% above the floor price) December 31
2,650 Bpd US $68.44 per bbl January 1 - June 30
250 Bpd Costless Collar US $66.00 floor,
US $69.25 ceiling January 1 - June 30
250 Bpd Costless Collar US $66.00 floor,
US $71.50 ceiling January 1 - June 30
250 Bpd US $71.24 per bbl July 1 - September 30
2,500 Bpd Participating Swap US $60.00 per bbl July 1 -
(max to 53.3% above the floor price) September 30
250 Bpd US $70.66 per bbl July 1 - December 31
250 Bpd Participating Swap US $70.00 per bbl July 1 -
(61.8% above the floor price) December 31
2,000 Bpd Participating Swap US $60.00 per bbl October 1 -
(max to 59% above the floor price) December 31
750 Bpd US $70.49 per bbl October 1 - December 31
150 Bpd Participating Swap US $60.00 per bbl January 1 -
(78% above the floor price) December 31
250 Bpd Participating Swap US $62.50 per bbl January 1 -
(57.5% above the floor price) December 31
250 Bpd Participating Swap US $65.00 per bbl January 1 -
(52% above the floor price) December 31
Natural
Gas 48,643 Mmbtu US $8.01 per mmbtu (10) January 1 - December 31

2009
Crude
Oil 125-325 Bpd US $59.25 per bbl January 1 - December 31
460 Bpd US $69.95 per bbl January 1 - December 31
679 Bpd US $71.38 per bbl January 1 - December 31
410 Bpd Participating Swap US $60.00 per bbl January 1 -
(max to 67.99% above the floor price) December 31
250 Bpd Participating Swap US $62.50 per bbl January 1 -
(max to 67.25% above the floor price) December 31
210 Bpd Costless Collar US $60.00 floor, January 1 -
US $79.50 ceiling December 31
250 Bpd Participating Swap US $70.00 per bbl January 1 -
(61.8% above the floor price) December 31
500 Bpd Participating Swap US $60.00 per bbl January 1 -
(max to 55.5% above the floor price) September 30
2,000 Bpd Participating Swap US $60.00 per bbl January 1 -
(max to 59% above the floor price) September 30
500 Bpd US $70.92 per bbl January 1 - March 31
500 Bpd US $72.25 per bbl April 1 - June 30
250 Bpd US $72.47 per bbl October 1 - December 31
250 Bpd Participating Swap US $60.00 per bbl October 1 -
(70% above the floor price) December 31
500 Bpd Participating Swap US $65.00 per bbl October 1 -
(54% above the floor price) December 31
500 Bpd Participating Swap US $65.00 per bbl October 1 -
(50% above the floor price) December 31
250 Bpd US $70.00 per bbl December 1 - December 31
425 Bpd Participating Swap US $60.00 per bbl January 1 -
(61.45% above the floor price) December 31
Natural
Gas 44,071 Mmbtu US $8.01 per mmbtu (10) January 1 - December 31

2010
Crude
Oil 609 Bpd US $70.42 per bbl January 1 - December 31
500 Bpd US $69.75 per bbl January 1 - December 31
933 Bpd Participating Swap US $60.00 per bbl January 1 -
(max to 59.01% above the floor price) December 31
250 Bpd Participating Swap US $62.50 per bbl January 1 -
(56.20% above the floor price) December 31
183 Bpd Costless Collar US $60.00 floor, January 1 -
US $79.25 ceiling December 31
183 Bpd US $69.59 per bbl January 1 - December 31
250 Bpd Participating Swap US $70.00 per bbl January 1 -
(61.8% above the floor price) March 31
250 Bpd Participating Swap US $60.00 per bbl
(70% above the floor price) January 1 - June 30
500 Bpd Participating Swap US $65.00 per bbl
(50% above the floor price) January 1 - June 30
250 Bpd US $72.47 per bbl January 1 - June 30
542 Bpd US $72.05 per bbl January 1 - July 31
500 Bpd Participating Swap US $70.00 per bbl April 1 -
(37.3% above the floor price) September 30
Natural
Gas 40,471 Mmbtu US $8.01 per mmbtu (10) January 1 - December 31

2011
Crude
Oil 1,377 Bpd Participating Swap US $60.00 per bbl January 1 -
(max to 53.11% above the floor price) December 31
177 Bpd Costless Collar US $60.00 floor,
US $77.60 ceiling January 1 - December 31
177 Bpd US $69.15 per bbl January 1 - December 31
Natural
Gas 40,400 Mmbtu US $8.01 per mmbtu (10) January 1 - March 31
---------------------------------------------------------------------------
---------------------------------------------------------------------------


Midstream

Year Volume
Product (Buy)Sell Terms Effective Period
---------------------------------------------------------------------------
2008
Crude
Oil 2,250 Bpd Costless Collar US $68.50 floor,
US $73.72 ceiling January 1 - December 31
500 Bpd Costless Collar US $64.00 floor,
US $74.50 ceiling January 1 - September 30
500 Bpd Costless Collar US $73.00 floor,
US $80.00 ceiling January 1 - June 30
250 Bpd US $65.60 per bbl January 1 - December 31
250 Bpd US $66.65 per bbl January 1 - December 31
9,635 Bpd Cdn $76.02 per bbl January 1 - December 31
(845) Bpd US $74.64 per bbl (4) January 1 - March 31
(10,535) Bpd US $86.93 per bbl (4) January 1 - March 31
Natural
Gas (75,767) Gjpd Cdn $8.31 per gj January 1 - December 31
Foreign
Exchange Sell US $6,202,175 per month
@ 1.1198 (5) January 1 - December 31
Sell US $1,107,166 per month
@ 1.1035 (5) January 1 - June 30
Sell US $974,222 per month
@ 1.1255 (5) January 1 - September 30
Propane 3,225 Bpd US $1.5308 per gallon (6)(9) January 1 - January 31
1,206 Bpd US $1.5382 per gallon (6)(9) February 1 - February 29
5,645 Bpd US $1.2829 per gallon (6)(9) January 1 - February 29
850 Bpd US $1.2487 per gallon (4)(6) January 1 - March 31
10,287 Bpd US $1.4595 per gallon (4)(6) January 1 - March 31
Normal
Butane 2,258 Bpd US $1.8148 per gallon (7)(9) January 1 - January 31
2,230 Bpd US $1.647 per gallon (4)(7) January 1 - March 31
150 Bpd US $1.4325 per gallon (4)(7) January 1 - March 31
ISO
Butane 150 Bpd US $1.4453 per gallon (4)(8) January 1 - March 31
1,720 Bpd US $1.6424 per gallon (4)(8) January 1 - March 31
Power (20) MW/hpd Cdn $76.43 per MW/h (12) January 1 - December 31

2009
Crude
Oil 2,500 Bpd Costless Collar US $64.80 floor,
US $69.36 ceiling January 1 - December 31
7,158 Bpd Cdn $74.23 per bbl January 1 - December 31
250 Bpd US $64.60 per bbl January 1 - December 31
250 Bpd US $66.65 per bbl January 1 - December 31
500 Bpd Costless Collar US $70.00 floor, January 1 -
US $79.00 ceiling June 30
1,000 Bpd Participating Swap US $63.13 per bbl July 1 -
(56% above the floor price) August 31
598 Bpd Participating Swap US $75.64 per bbl July 1 -
(55.7% above the floor price) November 30
500 Bpd Participating Swap Cdn $73.38 per bbl September 1 -
(48.9% above the floor price) November 30
Natural
Gas
(60,769) Gjpd Cdn $8.14 per gj January 1 - December 31
(2,792) Gjpd Participating Swap Cdn $7.73 per gj July 1 -
(39% below the ceiling price) November 30
(2,810) Gjpd Cdn $6.62 per gj September 1 - October 31
(2,810) Gjpd Costless Collar Cdn $6.20 floor,
Cdn $7.10 ceiling September 1 - October 31
Foreign
Exchange Sell US $6,699,029 per month
@ 1.1113 (5) January 1 - December 31
Sell US $1,055,833 per month
@ 1.099 (5) January 1 - June 30
Sell US $1,972,561 per month
@ 1.0245 (5) July 1 - August 31
Sell US $596,166 per month
@ 0.9815 (5) July 1 - October 31
Sell US $1,686,650 per month
@ 0.9620 (5) September 1 - October 31
Sell US $1,163,100 per month
@ 1.013 (5) November 1 - November 30

2010
Crude
Oil 1,500 Bpd Costless Collar US $62.90 floor,
US $67.48 ceiling January 1 - December 31
6,502 Bpd Cdn $73.16 per bbl January 1 - December 31
250 Bpd US $66.65 per bbl January 1 - December 31
500 Bpd Participating Swap Cdn $61.50 per bbl
(50% above the floor price) July 1 - August 31
376 Bpd Participating Swap Cdn $70.91 per bbl
(56% above the floor price) July 1 - October 31
820 Bpd Participating Swap US $73.63 per bbl
(51.8% above the floor price) January 1 - November 30
Natural
Gas (48,527) Gjpd Cdn $7.89 per gj January 1 - December 31
(4,089) Gjpd Participating Swap Cdn $7.62 per gj January 1 -
(31.3% below the ceiling price) November 30
Foreign
Exchange Sell US $4,721,469 per month
@ 1.1101 (5) January 1 - December 31
Sell US $582,821 per month
@ 1.0159 (5) January 1 - August 31
Sell US $1,407,419 per month
@ 0.9781 (5) July 1 - August 31
Sell US $587,903 per month
@ 1.0165 (5) July 1 - November 30
Sell US $2,254,103 per month
@ 0.9577 (5) September 1 - October 31
Sell US $1,750,992 per month
@ 1.0176 (5) September 1 - November 30
2011
Crude
Oil 5,389 Bpd Cdn $71.68 per bbl January 1 - December 31
250 Bpd Participating Swap US $63.00 per bbl
(64% above the floor price) January 1 - December 31
500 Bpd Costless Collar US $65.00 floor,
US $75.00 ceiling January 1 - June 30
2,000 Bpd Costless Collar US $58.50 floor,
US $72.69 ceiling July 1 - September 30
Natural
Gas (37,595) Gjpd Cdn $7.31 per gj January 1 - December 31
Foreign
Exchange Sell US $980,417 per month
@ 1.0805 (5) January 1 - June 30
Sell US $3,587,999 per month
@ 1.0931 (5) July 1 - September 30
Sell US $479,063 per month
@ 0.9725 (5) January 1 - December 31

2012
Crude
Oil 3,647 Bpd Cdn $72.95 per bbl January 1 - December 31
1,141 Bpd Participating Swap US $66.67 per bbl
(59% above the floor price) April 1 - December 31
250 Bpd Participating Swap Cdn $71.50 per bbl
(50% above the floor price) October 1 - December 31
Natural
Gas (25,787) Gjpd Cdn $7.23 per gj January 1 - December 31
Foreign
Exchange Sell US $1,437,986 per month
@ 0.9657 (5) July 1 - December 31
Sell US $976,436 per month
@ 0.9413 (5) April 1 - October 31
Sell US $1,634,227 per month
@ 0.9832 (5) October 1 - December 31

2013
Crude
Oil 250 Bpd Cdn $75.32 per bbl January 1 - January 31
750 Bpd Participating Swap US $70.92 per bbl January 1 -
(50.6% above the floor price) January 31
250 Bpd Participating Swap Cdn $71.50 per bbl January 1 -
(50% above the floor price) January 31
Natural
Gas (7,025) Gjpd Cdn $7.19 per gj January 1 - January 31
Foreign
Exchange Sell US $1,651,990 per month
@ 0.9832 (5) January 1 - January 31
---------------------------------------------------------------------------
---------------------------------------------------------------------------

Corporate
---------------------------------------------------------------------------
Year
Product (Buy)Sell Terms Effective Period
---------------------------------------------------------------------------
2008
Foreign
Exchange Sell US $9,000,000 @ .9701 (5.1) January 25
Sell US $3,000,000 @ 1.0105(5.1) February 25
Interest
Rate Pay Fixed rate of 4.8852% - Receive January 1 -
3M CAD BA on Cdn $50MM Notional (11) July 31
---------------------------------------------------------------------------
---------------------------------------------------------------------------
(1) The above table represents a number of transactions entered into over
an extended period of time.
(2) Natural Gas contracts are settled against AECO monthly index.
(3) Crude Oil contracts are settled against NYMEX WTI calendar average
(4) Conversion of Crude Oil BTU positions to liquids.
(5) US dollar contracts settled against Bank of Canada noon rate average.
(5.1) US dollar cashflows sold forward.
(6) Propane contracts are settled against Belvieu C3 TET.
(7) Normal Butane contracts are settled against Belvieu NC4 NON-TET.
(8) ISO Butane contracts are settled against Belvieu IC4 NON-TET.
(9) Midstream inventory price stabilization contracts.
(10) Natural Gas contracts are settled against Natural Gas-Michcon
Citygate Inside FERC.
(11) Settles quarterly against 3M CAD BA interest rate.
(12) Power contracts are settled monthly against the average hourly price
of electricity as published by the AESO in $/MWh.


14. Cash reserve for future site reclamation

Provident established a cash reserve effective May 1, 2001 for future site reclamation expenditures relating to its Canadian oil and gas production. In accordance with the royalty agreement, Provident funds the reserve by paying $0.30 per barrel of oil equivalent produced on a 6:1 basis into a segregated cash account. Actual expenditures incurred are then funded from the cash in this account. The cash reserve was depleted in 2006 as actual expenditures exceeded contributions to the reserve.

15. Commitments

Provident has office lease commitments that extend through June 2022. Future minimum lease payments for the following five years are: 2008 - $8.6 million; 2009 - $10.6 million; 2010 - $10.5 million; 2011 - $10.4 million; and 2012 - $10.2 million.

In relation to the midstream services and marketing segment, Provident is committed to minimum lease payments under the terms of various rail tank car leases for the following five years: 2008 - $6.6 million; 2009 - $5.4 million; 2010 - $3.9 million; 2011 - $2.7 million, and 2012 - $1.3 million. Additionally, under an arrangement to use a third party interest in the Younger plant, Provident has a commitment to make payments calculated with reference to a number of variables including return on capital. Payments for the next five years are estimated as follows: 2008 - $4.3 million; 2009 - $4.0 million; 2010 - $3.8 million; 2011 - $4.1 million and 2012 - $4.3 million.

In relation to the United States oil and natural gas production segment, Provident's U.S. subsidiaries have performance obligations that are secured, in whole or in part, by surety bonds. These obligations primarily cover self-insurance and other programs where governmental organizations require such support. These surety bonds are issued by financial institutions and are required to be reimbursed by Provident's U.S. subsidiaries if drawn upon. At December 31, 2007, Provident's U.S. subsidiaries had obtained various surety bonds for U.S. $14.3 million (2006 - U.S. $4.9 million).

In relation to the United States oil and natural gas production segment, Provident leases certain property and equipment under operating leases. Future minimum lease payments for the following five years are as follows: 2008 - U.S. $0.9 million; 2009 - U.S. $0.8 million; 2010 - U.S. $0.7 million; 2011 - U.S. $0.7 million and 2012 - U.S. $0.7 million.

16. Subsequent event

In February 2008, the Trust announced that it has retained Morgan Stanley as financial advisor in connection with a strategic review process with the objective of selling the operations that comprise the United States oil and natural gas production (USOGP) segment. USOGP includes the Trust's interest in the MLP, the related general partner interest, as well as the Trust's interest in BreitBurn Energy Company L.P.

As at December 31, 2007 the Trust owned approximately 22 percent of the MLP and approximately 96 percent of BreitBurn Energy Company L.P. Pursuant to the announcement, the Trust will account for USOGP as discontinued operations beginning in the first quarter of 2008.

17. Segmented information

The Trust's business activities are conducted through three business segments: Canadian oil and natural gas production (COGP), United States oil and natural gas production (USOGP) and Midstream.

Oil and natural gas production in Canada and the United States includes exploitation, development and production of crude oil and natural gas reserves. Midstream includes processing, extraction, transportation, loading and storage of natural gas liquids, and marketing of natural gas liquids.

Geographically the Trust operates in Canada and the USA in the oil and gas production business segment. The geographic components have been presented for the oil and natural gas business as well as the Midstream business that operates in both Canada and the USA.



Year ended December 31, 2007
-------------------------------------------------------
Canadian U.S. Total
Oil and Oil and Oil and
Natural Natural Natural
Gas Gas Gas Mid-
Production Production Production stream(1) Total
---------------------------------------------------------------------------
Revenue
Gross production
revenue $ 454,179 $ 278,414 $ 732,593 $ - $ 732,593
Royalties (87,046) (31,654) (118,700) - (118,700)
Product sales and
service revenue - - - 1,958,372 1,958,372
Realized gain
(loss) on financial
derivative
instruments 1 ,728 (7,959) (6,231) (74,474) (80,705)
---------------------------------------------------------------------------
368,861 238,801 607,662 1,883,898 2,491,560
---------------------------------------------------------------------------
Expenses
Cost of goods sold - 11,143 11,143 1,594,639 1,605,782
Production,
operating
and maintenance 112,387 81,699 194,086 14,094 208,180
Transportation 8,193 3,102 11,295 16,825 28,120
Foreign exchange
(gain) loss
and other (573) - (573) 3,996 3,423
General and
administrative 27,102 45,188 72,290 28,669 100,959
---------------------------------------------------------------------------
147,109 141,132 288,241 1,658,223 1,946,464
---------------------------------------------------------------------------
Earnings before
interest, taxes,
depletion,
depreciation,
accretion and other
non-cash items 221,752 97,669 319,421 225,675 545,096
Other revenue
Unrealized loss on
financial derivative (21,324) (110,040) (131,364) (192,920) (324,284)
---------------------------------------------------------------------------
Other expenses
Depletion,
depreciation and
accretion 256,723 50,253 306,976 44,388 351,364
Interest on
bank debt 11,055 7,439 18,494 33,166 51,660
Interest and
accretion on
convertible
debentures 3,672 10,660 14,332 11,015 25,347
Amortization of
deferred financing
charges - - - - -
Unrealized foreign
exchange loss
and other 779 2,593 3,372 - 3,372
Dilution gain - (260,324) (260,324) - (260,324)
Non-cash unit
based compensation 3,698 5,950 9,648 4,366 14,014
Internal management
charge (1,482) 1,482 - - -
Capital tax expense 3,762 - 3,762 - 3,762
Current and
withholding tax
(recovery) expense (254) 10 (244) 6,606 6,362
Future income tax
expense
(recovery)(2) (122,590) 58,843 (63,747) 94,234 30,487
---------------------------------------------------------------------------
155,363 (123,094) 32,269 193,775 226,044
Non- controlling
interest - USOGP - (35,666) (35,666) - (35,666)
Non- controlling
interest -
exchangeables - - - - -
---------------------------------------------------------------------------
Net income (loss) for
the period $ 45,065 $ 146,389 $ 191,454 $(161,020) $ 30,434
---------------------------------------------------------------------------
---------------------------------------------------------------------------
(1) Included in the Midstream segment is product sales and service revenue
of $297.8 million associated with U.S. operations.
(2) Future income tax expense (recovery) includes a charge of $88.4 million
relating to the enactment of Bill C- 52, Budget Implementation Act 2007
by the Canadian government (see note 12).



As at and for the year ended December 31, 2007
-------------------------------------------------------
Canadian U.S. Total
Oil and Oil and Oil and
Natural Natural Natural
Gas Gas Gas
Production Production Production Midstream Total
---------------------------------------------------------------------------
Selected balance sheet items
Capital assets
Property, plant
and equipment
net $1,773,209 $2,008,549 $3,781,758 $737,062 $4,518,820
Intangible assets - 3,763 3,763 171,793 175,556
Goodwill 416,890 - 416,890 100,409 517,299
Capital expenditures
Capital
expenditures 146,209 69,009 215,218 31,904 247,122
Corporate
acquisitions 469,795 - 469,795 - 469,795
Oil and gas property
acquisitions, net 13,050 1,015,803 1,028,853 - 1,028,853
Goodwill additions 85,946 - 85,946 - 85,946
Working capital
Accounts receivable 75,292 79,457 154,749 262,813 417,562
Petroleum product
inventory - 5,636 5,636 84,638 90,274
Accounts payable
and accrued
liabilities 132,452 77,442 209,894 214,574 424,468
Long-term debt -
revolving term
credit facilities 230,999 368,836 599,835 692,997 1,292,832
Long-term debt -
convertible
debentures 35,129 115,925 151,054 105,386 256,440
Financial derivative
instruments $ 13,559 $ 102,859 $ 116,418 $261,587 $ 378,005
---------------------------------------------------------------------------
---------------------------------------------------------------------------



Year ended December 31, 2006
-------------------------------------------------------
Canadian U.S. Total
Oil and Oil and Oil and
Natural Natural Natural
Gas Gas Gas Mid-
Production Production Production stream(1) Total
---------------------------------------------------------------------------
Revenue
Gross production
revenue $ 402,095 $ 176,160 $ 578,255 $ - $ 578,255
Royalties (81,225) (17,315) (98,540) - (98,540)
Product sales and
service revenue - - - 1,764,392 1,764,392
Realized gain
(loss) on financial
derivative
instruments 4,371 (2,505) 1,866 (15,406) (13,540)
---------------------------------------------------------------------------
325,241 156,340 481,581 1,748,986 2,230,567
---------------------------------------------------------------------------
Expenses
Cost of goods sold - - - 1,471,171 1,471,171
Production,
operating and
maintenance 97,626 52,008 149,634 22,619 172,253
Transportation 5,114 - 5,114 14,672 19,786
Foreign exchange
gain and other (9) - (9) (2,728) (2,737)
Cash general and
administrative 24,065 26,519 50,584 23,621 74,205
---------------------------------------------------------------------------
126,796 78,527 205,323 1,529,355 1,734,678
---------------------------------------------------------------------------
Earnings before
interest, taxes,
depletion,
depreciation,
accretion and other
non-cash items 198,445 77,813 276,258 219,631 495,889
Other revenue
Unrealized gain
(loss) on financial
derivative
instruments 17,299 7,735 25,034 (68,348) (43,314)
---------------------------------------------------------------------------
Other expenses
Depletion,
depreciation and
accretion 168,953 31,058 200,011 49,128 249,139
Interest on
bank debt 10,082 4,861 14,943 19,723 34,666
Interest and
accretion on
convertible
debentures 5,746 5,828 11,574 12,345 23,919
Amortization of
deferred
financing charges 956 786 1,742 2,112 3,854
Unrealized foreign
exchange loss
and other - - - 418 418
Dilution gain - - - - -
Non-cash unit
based compensation 4,320 12,476 16,796 6,287 23,083
Internal management
charge (1,280) 1,280 - - -
Capital tax expense 1,314 - 1,314 - 1,314
Current and withholding
tax expense (2,124) 3,332 1,208 4,621 5,829
Future income tax
expense (recovery) (56,161) 20,297 (35,864) 1,548 (34,316)
---------------------------------------------------------------------------
131,806 79,918 211,724 96,182 307,906
Non-controlling
interest - USOGP - 2,995 2,995 - 2,995
Non-controlling
interest -
exchangeables 485 37 522 232 754
---------------------------------------------------------------------------
Net income for
the period $ 83,453 $ 2,598 $ 86,051 $ 54,869 $ 140,920
---------------------------------------------------------------------------
---------------------------------------------------------------------------
(1) Included in the Midstream segment is product sales and service revenue
of $332.9 million associated with U.S. operations.



As at and for the year ended December 31, 2006
-------------------------------------------------------
Canadian U.S. Total
Oil and Oil and Oil and
Natural Natural Natural
Gas Gas Gas
Production Production Production Midstream Total
---------------------------------------------------------------------------
Selected balance sheet items
Capital assets
Property, plant
and equipment
net $1,211,112 $ 380,451 $1,591,563 $741,974 $2,333,537
Intangible assets - - - 193,592 193,592
Goodwill 330,944 - 330,944 100,409 431,353
Capital expenditures
Capital
expenditures 70,088 54,337 124,425 66,008 190,433
Corporate
acquisitions - - - 1,036 1,036
Oil and gas property
acquisitions, net 483,633 (2,008) 481,625 - 481,625
Goodwill additions - - - 2,285 2,285
Working capital
Accounts receivable 58,250 24,744 82,994 187,141 270,135
Petroleum product
inventory - - - 85,868 85,868
Accounts payable
and accrued
liabilities 86,305 52,626 138,931 156,072 295,003
Long-term debt -
revolving term
credit
facilities 172,980 11,072 184,052 518,941 702,993
Long-term debt -
convertible
debentures 44,553 117,470 162,023 123,769 285,792
Financial derivative
instruments (asset)
liability $ (7,520) $ (8,417) $ (15,937) $ 68,795 52,858
---------------------------------------------------------------------------
---------------------------------------------------------------------------


18. Related party transactions

Included in accounts receivable as at December 31, 2007 is $32.8 million with related parties. Of this amount, $22.5 million represents a net receivable from Quicksilver, reflecting cash collections made on behalf of a subsidiary of the Trust in connection with the acquisition of assets from Quicksilver in the fourth quarter of 2007, net of advances. Quicksilver owns approximately 32 percent of the outstanding units of the MLP, a subsidiary of the Trust. The remaining $10.3 million relates to sales of crude oil by a subsidiary of the trust to a buyer whose Chairman of the Board and Chief Executive Officer is also a director of the general partner of the subsidiary of the Trust.

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

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



Consolidated Statements of Earnings - U.S. GAAP
For the year ended December 31, (Cdn $000s) 2007 2006
---------------------------------------------------------------------------
Net income as reported $ 30,434 $ 140,920
Adjustments
Depletion, depreciation and accretion (a) 72,485 12,146
Depletion, depreciation and accretion other (a) (181,551) (382,230)
General and administrative (d) 483 (483)
Future income tax recovery (a) (b) 23,625 110,898
Accretion on convertible debentures (e) 2,802 2,694
Non-controlling interest (2,895) 754
---------------------------------------------------------------------------
Net loss - U.S. GAAP $ (54,617) $ (115,301)
Other comprehensive (loss) income (26,000) (509)
---------------------------------------------------------------------------
Comprehensive income (loss) (80,617) (115,810)
---------------------------------------------------------------------------
Net loss per unit - basic and diluted $ (0.24) $ (0.59)
---------------------------------------------------------------------------
---------------------------------------------------------------------------


Condensed Consolidated Balance Sheet
As at December 31, (Cdn$ 000s) 2007 2006
---------------------------------------------------------------------------
Canadian U.S. Canadian U.S.
GAAP GAAP GAAP GAAP
---------------------------------------------------------------------------
Assets
Deferred financing charges (e) $ - $ 14,809 $ 12,351 $ 12,351
Property, plant and
equipment (a) 4,518,820 3,983,181 2,333,537 1,906,964
Liabilities and unitholders' equity
Current portion of
convertible debentures (e) 19,198 19,931 - -
Long-term debt - revolving term
credit facilities (e) 1,292,832 1,300,645 702,993 702,993
Long-term debt - convertible
debentures (e) 256,440 274,113 285,792 300,110
Other long-term
liabilities (d) 20,759 20,759 16,305 16,788
Future income taxes (a) (b) 450,000 296,597 309,006 180,122
Non-controlling interests 1,100,136 1,103,031 81,111 81,111
Units subject to
redemption (f) - 2,308,273 - 2,317,196
Convertible debentures
equity component (e) 18,213 - 18,522 -
Unitholders'
contributions (f) 2,750,374 - 2,254,048 -
Accumulated other
comprehensive (loss) income (69,188) (69,188) (42,294) (43,187)
Accumulated income (loss) 268,642 (927,762) 238,208 (1,044,840)
Accumulated cash
distributions (f) (1,260,177) - (926,825) -

---------------------------------------------------------------------------
---------------------------------------------------------------------------


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

In computing its consolidated net earnings for U.S. GAAP purposes, the Trust recorded additional depletion in 2007 of $181.6 million (2006 - $382.2 million) and a related future income tax recovery of $52.2 million (2006 - $114.7 million) as a result of the application of the ceiling test. These charges were not required under the Canadian GAAP ceiling tests.

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

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

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

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

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

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

(e) Under Canadian GAAP Provident applies EIC Abstract 164 "Convertible and other instruments with embedded derivatives" to account for the convertible debentures. Under U.S. GAAP, the convertible debentures are disclosed as long-term debt at their face value versus Canadian GAAP that requires discounting of the convertible debentures, accretion expense to represent the unwinding of the discounted convertible debentures and a value assigned within equity to the conversion feature component of the convertible debentures. In addition, U.S. GAAP requires debt issue costs to be reported as deferred charges on the consolidated balance sheet.

(f) Under U.S. GAAP, a redemption feature of equity instruments exercisable at the option of the holder requires that such equity be excluded from classification as permanent equity and be reported as temporary equity at the equity's redemption value. Changes in redemption value in the period (2007 - $505.1 million; 2006 - $188.6 million) are recorded to accumulated earnings. Under Canadian GAAP, such equity instruments are considered to be permanent equity and are presented as unitholder's equity. The Trust's units have a redemption feature, which qualify them to be considered under this guidance.

Recent U.S. Accounting Pronouncements

Non-controlling interests in consolidated financial statements

In December 2007, the FASB issued FAS 160 "Non-controlling interests in Consolidated Financial Statements." FAS 160 requires the ownership interests in subsidiaries held by parties other than the parent be clearly presented in the consolidated balance sheet within equity, but separate from the parent's equity and the amount of consolidated net income attributable to the parent and the non-controlling interest be clearly identified and presented on the face of the consolidated statement of operations. Changes in the parent's ownership interest should be accounted for consistently as equity transactions. If a subsidiary is deconsolidated, any retained non-controlling equity investment in the former subsidiary should be initially recorded at fair value and the gain or loss on the deconsolidation of the subsidiary is measured using the fair value of any non-controlling equity investment rather than the carrying amount of the retained investment. This statement is effective for fiscal years, and interim periods, beginning on or after December 15, 2008. The application of this standard will impact how the Trust's balance sheet and statement of operations are presented.

Business combinations

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

The fair value option for financial assets and financial liabilities

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

Fair value measurement

In September 2006, the FASB issued FAS 157 "Fair value measurement." FAS 157 defines fair value, establishes a framework for measuring fair value in generally accepted accounting principles and expands disclosures about fair value measurements. This statement does not require any new fair value measurements. Fair value is defined in this statement as the exchange price, which is the price in an orderly transaction between market participants to sell the asset or transfer the liability in the market in which the reporting entity would transact for the asset or liability, that is, the principal or most advantageous market for the asset or liability. The statement is effective for financial statements issued for fiscal years beginning after November 15, 2007, and interim periods of those fiscal years. The Trust is currently evaluating the effect that this statement might have on the Trust's financial statements.

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:
    800, 112 - 4th Avenue S.W.
    Calgary, Alberta T2P 0H3
    (403) 296-2233 or Toll Free: 1-800-587-6299
    (403) 294-0111 (FAX)
    Website: www.providentenergy.com