Provident Energy Trust
TSX : PVE.UN
NYSE : PVX

Provident Energy Trust

August 07, 2008 18:01 ET

Provident Reports Second Quarter Results, Increases 2008 Capital Program, and Announces August Distribution

CALGARY, ALBERTA--(Marketwire - Aug. 7, 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 exceptional results in the second quarter of 2008." said Provident President and Chief Executive Officer, Tom Buchanan. "The combination of our high-quality energy assets and strong commodity prices provided record second quarter funds flow from operations of $241 million and a payout ratio of 43 per cent. We continue to execute on our strategic objectives and with the sale of our interest in BreitBurn, Provident has taken significant steps towards unlocking value and improving strategic flexibility."

Highlights

- Consolidated funds flow from operations in the second quarter was $241 million ($0.95 per unit), up 145 per cent from $99 million ($0.45 per unit) in the second quarter of 2007.

- Distributions for the second quarter were $0.36 per unit, resulting in a consolidated payout ratio of 43 per cent, an improvement from the 85 per cent payout for the second quarter of 2007.

- Provident completed the sale of its 22 per cent interest in BreitBurn Energy Partners L.P. ("the MLP") and controlling interest in BreitBurn GP LLC, the general partner for the MLP, for gross proceeds of $350 million. Subsequent to the close of the second quarter, Provident announced an agreement to sell BreitBurn Energy Company L.P. ("BreitBurn") for gross proceeds of $310 million which is expected to close prior to the end of August. Combined after tax proceeds are estimated to be $440 million and will be used to reduce debt.


- Strong funds flow coupled with the application of second quarter divestiture proceeds to the Canadian senior credit facility have resulted in a net debt to annualized second quarter funds flow from continuing operations of 1.4 times down from 3.3 times a year earlier.

- Production from the Canadian Oil and Gas business unit averaged approximately 28,000 barrels of oil equivalent per day (boed) in the second quarter, increasing nine per cent from 25,700 boed in the second quarter of 2007.

- Funds flow from operations in the Canadian Oil and Gas business were $113 million in the second quarter of 2008, up 117 per cent from $52 million one year earlier due to strong netbacks and increased production.

- Midstream delivered very strong second quarter earnings before interest, taxes, depletion, depreciation, accretion and other non-cash items (EBITDA) of $62 million, up 72 per cent from $36 million in the second quarter of 2007 due to strong condensate demand and robust NGL prices.

2008 Capital Program

Provident is increasing its 2008 capital budget for the Canadian Oil and Gas Production business unit from $134 million to approximately $190 million, an increase of 42 per cent. The strength of commodity markets and performance of Provident's E&P assets, provide a compelling opportunity for increasing the development program. Provident continues to increase its focus on full-cycle oil and natural gas development opportunities. The incremental capital spending will be directed towards enhancement of Provident's land position in high impact areas, acceleration of the drilling program, optimization of existing assets, and the development of longer term opportunities that focus on production growth in 2009 and beyond.

Provident anticipates total capital expenditures for the Midstream business will remain within the $43 million budget previously disclosed. The revised total capital budget for continuing operations is $233 million for 2008.

Provident is narrowing its previous full-year production guidance range from 26,000 to 28,000 boed to a range of 27,000 to 28,000 boed due to the strong performance of the Canadian Oil and Gas business unit and the increased capital program.

August Distribution

Provident's August cash distribution will be CDN$0.12 per unit payable on September 15, 2008. The August distribution will be paid to unitholders of record on August 22, 2008. The ex-distribution date will be August 20, 2008. The Trust's current annualized cash distribution rate is CDN$1.44 per trust unit. Based on the current annualized distribution rate and the closing price on August 7, 2008 of $10.78, Provident's yield is approximately 13.4 per cent.

For unitholders receiving their distribution in U.S. funds, the August 2008 cash distribution will be approximately US$0.11 per unit based on an exchange rate of 0.9514. The actual U.S. dollar distribution will depend on the Canadian/U.S. dollar exchange rate on the payment date and will be subject to applicable withholding taxes.

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

Consolidated
($ 000s except per Three months Six months
unit data) ended June 30, ended June 30,
----------------------------------------------------------------------------
% %
2008 2007 Change 2008 2007 Change
----------------------------------------------------------------------------

Revenue (net of
royalties and
financial derivative
instruments) from
continuing
operations $ 420,220 $463,995 (9)$1,122,435 $1,022,802 10
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Funds flow from COGP
operations (1) $ 112,869 $ 52,032 117 $ 184,011 $ 98,442 87
Funds flow from
Midstream
operations (1) 52,601 29,569 78 111,853 68,973 62
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Funds flow from
continuing
operations 165,470 81,601 103 295,864 167,415 77
Funds flow from
discontinued
operations
(USOGP) (1) (3) 76,017 16,902 350 125,853 18,128 594
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Total funds flow
from operations
(1) $ 241,487 $ 98,503 145 $ 421,717 $ 185,543 127
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Per weighted
average unit -
basic and
diluted (2) $ 0.95 $ 0.45 111 $ 1.66 $ 0.86 93
Distributions
to unitholders $ 91,662 $ 80,236 14 $ 182,779 $ 156,507 17
Per unit $ 0.36 $ 0.36 - $ 0.72 $ 0.72 -
Percent of funds
flow from operations
paid out as declared
distributions (4) 43% 85% (49) 49% 88% (44)
Net loss $(184,081)$(46,199) 298 $ (150,465)$ (3,106) 4,744
Per weighted average
unit - basic and
diluted (2) $ (0.72)$ (0.21) 243 $ (0.59)$ (0.01) 5,800
Capital expenditures
(continuing
operations) $ 34,210 $ 27,360 25 $ 118,792 $ 66,113 80
Capitol Energy
acquisition $ - $467,850 $ - $ 467,850
Oil and gas property
acquisitions, net
(continuing
operations) $ 10,432 $ 1,028 $ 19,451 $ 9,709
Proceeds on sale of
discontinued
operations, net
of tax $ 206,349 $ - $ 206,349 $ -
Weighted average
trust units
outstanding
(000s)
- Basic 254,404 216,845 17 253,659 214,301 18
- Diluted (2) 254,468 217,085 17 253,723 214,541 18
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Consolidated
----------------------------------------------------------------------------
As at As at
June 30, December 31,
($ 000s) 2008 2007 % Change
----------------------------------------------------------------------------
Capitalization
Long-term debt (including current
portion) $ 904,461 $ 1,199,634 (25)
Unitholders' equity $ 1,443,755 $ 1,708,665 (16)
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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 and convertible debentures.
(3) Effective in the first quarter of 2008, Provident's USOGP business is
accounted for as discontinued operations (see note 10 of interim
consolidated financial statements).
(4) Calculated as distributions to unitholders divided by funds flow from
operations less distributions to non-controlling interests of $51.4
million year-to-date and $26.5 million for the quarter (2007 - $7.1
million and $3.5 million, respectively).


Operational highlights
Three months Six months
ended June 30, ended June 30,
----------------------------------------------------------------------------
% %
2008 2007 Change 2008 2007 Change
----------------------------------------------------------------------------

Oil and Gas
Production
Daily production -
COGP (continuing
operations)
Crude oil (bpd) 12,494 8,610 45 12,390 8,354 48
Natural gas liquids
(bpd) 1,178 1,311 (10) 1,243 1,366 (9)
Natural gas (mcfpd) 86,130 94,437 (9) 85,050 91,698 (7)
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COGP oil equivalent
(boed) (1) 28,027 25,660 9 27,808 25,003 11
USOGP (discontinued
operations) oil
equivalent
(boed) (1) 21,551 9,233 133 23,146 8,660 167
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Consolidated oil
equivalent (boed)
(1) 49,578 34,893 42 50,954 33,663 51
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Average realized
price from
continuing
operations
(before realized
financial
derivative
instruments)
Crude oil blend
($/bbl) $ 105.13 $ 53.75 96 $ 90.22 $ 52.54 72
Natural gas liquids
($/bbl) $ 94.59 $ 52.79 79 $ 83.15 $ 50.84 64
Natural gas
($/mcf) $ 9.98 $ 7.27 37 $ 8.81 $ 7.37 20
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Oil equivalent
($/boe) (1) $ 81.50 $ 47.48 72 $ 70.86 $ 47.36 50
----------------------------------------------------------------------------
Field netback from
continuing
operations (before
realized financial
derivative
instruments)
($/boe) $ 52.39 $ 27.70 89 $ 44.54 $ 27.00 65
Field netback from
continuing
operations
(including
realized financial
derivative
instruments)
($/boe) $ 48.76 $ 27.12 80 $ 42.12 $ 26.52 59
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Midstream
Midstream NGL sales
volumes (bpd) 110,826 109,713 1 123,573 117,331 5
EBITDA (000s) (2) $ 61,769 $ 35,974 72 $ 137,756 $ 88,827 55
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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".


Management's discussion and analysis

The following analysis dated August 7, 2008 provides a detailed explanation of Provident Energy Trust's ("Provident's") operating results for the three and six months ended June 30, 2008 compared to the same time periods in 2007 and should be read in conjunction with the consolidated financial statements of Provident, found later in the interim report.

Provident Energy Trust has diversified investments in certain segments of the energy value chain. Provident currently operates in two key business segments: Canadian crude oil and natural gas production ("COGP"), and Midstream. Provident's COGP business produces crude oil and natural gas from seven core areas in the western Canadian sedimentary basin. The Midstream business unit operates in Canada and the U.S.A. and extracts, processes, markets, transports and offers storage of natural gas liquids within the integrated facilities at Younger in British Columbia, Redwater and Empress in Alberta, Kerrobert in Saskatchewan, Sarnia in Ontario, Superior in Wisconsin and Lynchburg in Virginia. Effective in the first quarter of 2008, Provident's United States oil and natural gas production ("USOGP") business is accounted for as discontinued operations and comparative figures have been reclassified to conform with this presentation (see note 10 of the interim consolidated financial statements). USOGP produces crude oil and natural gas in California, Wyoming, Texas, Florida, Michigan, Indiana and Kentucky.

This analysis commences with a summary of the consolidated financial and operating results followed by segmented reporting on the COGP 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.

Second quarter and six months ended June 30, 2008 highlights

The second quarter highlights section provides commentary for the second quarter and for the six months ended June 30, 2008 and for corresponding periods in 2007.

Effective in the first quarter of 2008, Provident's United States oil and natural gas production (USOGP) business is accounted for as discontinued operations (see note 10 of the interim consolidated financial statements).

In June, 2008, Provident sold a portion of the USOGP business, consisting of its 22 per cent interest in BreitBurn Energy Partners, L.P. (MLP) and its 96 per cent interest in BreitBurn GP LLC, for cash proceeds, net of transaction costs, of U.S. $342.2 million. The Trust has recorded a gain on sale of $187.9 million and $141.8 million in current tax expense, related to this transaction. The future income tax recovery related to the MLP for the six months ended June 30, 2008 was $91.6 million. Also recorded was a realized foreign exchange loss of $30.3 million, representing the recognition of the related portion of the foreign exchange loss in accumulated other comprehensive income, which was generated since acquisition in 2006. These amounts are recorded as part of net income from discontinued operations for the three and six months ended June 30, 2008.

In July, 2008 the Trust announced an agreement to sell the remaining portion of the USOGP business, comprised of an approximate 96 per cent interest in BreitBurn Energy Company L.P., for total consideration of U.S. $305 million, consisting of cash proceeds of U.S. $295 million and a U.S. $10 million note. The transaction is expected to close prior to the end of August with proceeds initially applied to Provident's Canadian credit facility.



Consolidated funds flow from operations and cash distributions

Three months Six months
Consolidated ended June 30, ended June 30,
----------------------------------------------------------------------------
($ 000s, except per % %
unit data) 2008 2007 Change 2008 2007 Change
----------------------------------------------------------------------------
Funds Flow from
Operations and
Distributions
Funds flow from
continuing
operations $ 165,470 $ 81,601 103 $ 295,864 $ 167,415 77
Funds flow from
discontinued
operations 76,017 16,902 350 125,853 18,128 594
----------------------------------------------------------------------------
Total funds flow
from operations $ 241,487 $ 98,503 145 $ 421,717 $ 185,543 127
Per weighted average
unit - basic and
diluted $ 0.95 $ 0.45 111 $ 1.66 $ 0.86 93
----------------------------------------------------------------------------
Declared
distributions $ 91,662 $ 80,236 14 $ 182,779 $ 156,507 17
Per Unit 0.36 0.36 - 0.72 0.72 -
Percent of funds
flow from operations
distributed (2) 43% 85% (49) $ 49% $ 88% (44)
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----------------------------------------------------------------------------
(1) Includes dilutive impact of unit options and convertible debentures.
(2) Calculated as declared distributions to unitholders divided by funds
flow from operations less distributions to non-controlling interests of
$51.4 million year-to-date and $26.5 million for the quarter (2007 -
$7.1 million and $3.5 million, respectively).


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 operating 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.

Second quarter 2008 funds flow from operations was $241.5 million, 145 per cent above the $98.5 million recorded in the second quarter of 2007. For the six month period ended June 30, 2008 funds flow from operations was $421.7 million, 127 per cent above the $185.5 million in the same period of 2007. COGP provided 47 per cent of second quarter 2008 funds flow from operations, Midstream added 22 per cent and USOGP generated the remaining 31 per cent.

COGP 2008 second quarter funds flow from operations was $112.9 million, a 117 per cent increase from the $52.0 million recorded in the comparable 2007 quarter. This increase was a result of increased realized crude oil, natural gas liquids and natural gas prices combined with higher production from the acquisitions of Capitol Energy Resources Ltd. on June 19, 2007 ("Capitol") and Triwest Energy Inc. on December 3, 2007 ("Triwest"), and the successful execution of the drilling and development program. For the six month period ended June 30, 2008 COGP funds flow from operations was $184.0 million, an 87 per cent improvement above the $98.4 million recorded in the comparable 2007 period.

The Midstream business unit contributed $52.6 million to the second quarter of 2008 funds flow from operations, 78 per cent above the $29.6 million recorded in the comparable 2007 quarter, reflecting a 72 per cent increase in earnings before interest, taxes, depletion, depreciation, accretion and other non-cash items (EBITDA). The increase reflects higher price-driven per barrel margins, partially offset by an increase in the realized loss on financial derivative instruments. For the six months ended June 30, 2008, Midstream contributed $111.9 million to funds flow from operations, a 62 per cent increase from the $69.0 million in the comparable 2007 period.

Funds flow from discontinued operations (USOGP) in the second quarter of 2008 was $76.0 million, compared to $16.9 million in the second quarter of 2007. 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. For the six months ended June 30, 2008, funds flow from discontinued operations (USOGP) was $125.8 million, compared to the $18.1 million in the comparable 2007 period.

Declared distributions in the second quarter of 2008 totaled $91.7 million compared to $80.2 million of declared distributions in 2007. This represented 43 per cent and 85 per cent of funds flow from operations, respectively, after distributions to non-controlling interests of $26.5 million (2007 - $3.5 million). On a segmented basis, the Midstream business, due to its low sustaining capital requirements, effectively contributed 96 per cent of its funds flow from operations for distribution in the three months ended June 30, 2008. The remaining distributions were effectively contributed by the oil and natural gas production businesses (COGP and USOGP) representing 25 per cent of its funds flow from operations in the second quarter of 2008, after distributions to non-controlling interests of $26.5 million.

Outlook

Crude oil prices reached record levels for the second consecutive quarter, while natural gas and natural gas liquids (NGL) prices also saw upward movement during the first half of 2008. Moving into August, crude oil and natural gas prices have retreated from recent highs but the market outlook remains positive for the second half of the year.

In the second quarter, Provident's Canadian Oil and Gas Production business (COGP) increased daily production to approximately 28,000 boed, up nine per cent from 25,700 boed in the second quarter of 2007. Production is balanced at 51 per cent natural gas, and 49 per cent crude oil and NGL after the successful integration of oil-weighted acquisitions in 2007, including Capitol Energy and Triwest Resources. This has resulted in strong cash flow growth as crude prices have increased approximately 90 per cent over the same period last year. The favorable price environment incented Provident to incur expenditures to bring on some higher-cost production which will provide strong netbacks and increase cash flow. In the current business environment the economics of this production are very compelling, but the overall operating costs of the business unit are higher as a result. Provident expects fuel, power, labor and maintenance costs across oil and natural gas operations to remain high for the remainder of the year.

Provident's Midstream business unit increased EBITDA by 72 per cent in the second quarter to $61.8 million as a result of robust NGL prices and increased demand for condensate in Provident's Redwater West business line. Provident made effective use of its transportation and storage assets to increase condensate sales in the quarter. Midstream continues to build summer inventory for sale during the winter season when product demand is expected to strengthen. At the end of the second quarter, the Midstream business had spent $11.1 million of its projected $43 million capital budget on maintenance and the construction of two storage caverns at Provident's Redwater facility, anticipated to be in-service in early 2009. Curtailment of 6,000 bpd of leased fractionation capacity in Sarnia, effective April 1, 2009, has prompted the assessment of several options to mitigate this constraint. Alternatives include the reallocation of existing capacity, facility optimization or expansion which would allow Provident to produce and sell additional propane-plus volumes at a Provident operated facility in Western Canada. The majority of the remaining 2008 Midstream capital budget will likely be allocated towards the 2008 portion of the ensuing costs. Provident expects another excellent year in our Midstream business with 2008 EBITDA anticipated to be similar to that achieved in 2007 assuming continued favourable commodity prices and typical seasonal demand patterns.

Provident's net earnings will continue to be impacted by long term unrealized losses on financial derivative instruments while energy prices remain volatile. Because the Midstream commodity price risk management program extends up to five years and unrealized gains and losses for the full term of each derivative contract must be booked in the current quarter, net earnings are subject to substantial quarterly variation that is not necessarily related to current operations or cash flow. The Canadian Oil and Gas Production business manages commodity price risk on a two-year time horizon. Provident's financial derivative instruments are all backed by physical production, throughput or inventory.

On June 17, 2008, Provident announced the sale of a large part of its US Oil and Gas operations including its 22 per cent interest in BreitBurn Energy Partners LP (the MLP). On July 30, 2008 Provident announced an agreement to sell the remaining portion of USOGP, BreitBurn Energy Company L.P. (BreitBurn). This transaction is expected to close prior to the end of August. Total gross proceeds from the USOGP dispositions are anticipated to be $660 million. After tax proceeds are expected to be approximately $440 million. Consistent with the presentation in the first quarter, Provident's USOGP business is accounted for as discontinued operations.

Provident's previously announced strategic review of the Canadian Oil and Gas Production and Midstream businesses continues with the objective of defining the optimal structure for its businesses, particularly in response to the federal SIFT (specified investment flow-through) tax legislation and the current challenges of the capital markets. The overall objectives of the strategic review are to enhance unitholder value, improve access to and the cost of capital to facilitate growth, and to optimize the structure of our business units to be competitive in advance of the pending 2011 taxation on income trusts. Provident will continue its analysis of structural and strategic alternatives for the Canadian Oil and Gas Production and Midstream divisions.



Net income

Three months Six months
Consolidated ended June 30, ended June 30,
----------------------------------------------------------------------------
($ 000s, except per % %
unit data) 2008 2007 Change 2008 2007 Change
----------------------------------------------------------------------------

Net loss $ (184,081)$(46,199) 298 $ (150,465) $(3,106) 4,744
Per weighted average
unit - basic (1)
and diluted (2) $ (0.72)$ (0.21) 243 $ (0.59) $ (0.01) 5,800
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(1) Based on weighted average number of trust units outstanding.
(2) Based on weighted average number of trust units outstanding including
the dilutive impact of the unit option plan and convertible debentures.


Net loss for the second quarter of 2008 was $184.1 million compared to $46.2 million in the comparable 2007 quarter. An $87.5 million, or 96 per cent, increase in EBITDA combined with higher income from discontinued operations and higher future income tax recoveries were more than offset by a $382.8 million increase in unrealized loss on financial derivative instruments and increased depletion, depreciation and accretion.

The COGP business segment's second quarter 2008 net income was $28.9 million, a decrease of $21.5 million compared to the 2007 second quarter net income of $50.4 million. Increased operating earnings were more than offset by unrealized losses on financial derivative instruments and increased depletion, depreciation, and accretion resulting from the acquisitions of Capitol and Triwest. In addition, second quarter 2007 future income tax recovery included $29.8 million of recovery associated with the Canadian Government's enactment of legislation to tax publicly traded trusts, including Provident, commencing in 2011. No similar recovery was recorded in 2008.

The Midstream segment's net loss was $290.2 million in the second quarter of 2008 as compared to a $142.2 million net loss in the second quarter of 2007. A $25.8 million, or 72 per cent increase in EBITDA and a future income tax recovery was more than offset by a $347.0 million increase in the second quarter from unrealized loss on financial derivative instruments. In addition, second quarter 2007 future income tax expense included $134.5 million recorded against Midstream income associated with the Canadian Government's enactment of legislation to tax publicly traded trusts, including Provident, commencing in 2011. No similar charge was recorded in 2008.

In the second quarter of 2008, net income from discontinued operations (USOGP) was $77.2 million as compared to 2007 second quarter net income of $45.6 million. Increased operating earnings and the impact of the gain on sale of discontinued operations were offset by increased unrealized losses on financial derivative instruments.

Provident's 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 quarterly variation that is not necessarily related to current operations.

Reconciliation of non-GAAP measures

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



EBITDA Three months Six months
Reconciliation ended June 30, ended June 30,
----------------------------------------------------------------------------
% %
($ 000s) 2008 2007 Change 2008 2007 Change
----------------------------------------------------------------------------
EBITDA $ 178,901 $ 91,431 96 $ 330,236 $194,040 70
Adjusted for:
Cash interest (13,727) (10,758) 28 (29,176) (22,658) 29
Unrealized loss on
financial derivative
instruments (406,537) (23,746) 1,612 (468,810) (2,879) 16,184
Depletion,
depreciation and
accretion and other
non-cash expenses (91,487) (75,280) 22 (166,477) (145,545) 14
----------------------------------------------------------------------------
(Loss) income from
continuing operations
before taxes $(332,850) $(18,353) 1,714 $(334,227) $22,958 -
----------------------------------------------------------------------------
----------------------------------------------------------------------------

Reconciliation of funds
flow from operations to Three months Six months
distributions ended June 30, ended June 30,
----------------------------------------------------------------------------
% %
2008 2007 Change 2008 2007 Change
----------------------------------------------------------------------------
Cash provided by
operating
activities $ 46,473 $ 85,899 (46) $ 347,326 $236,470 47
Change in non-cash
operating working
capital 193,913 12,080 1,505 71,753 (52,677) -
Site restoration
expenditures 1,101 524 110 2,638 1,750 51
----------------------------------------------------------------------------
Funds flow from
operations 241,487 98,503 145 421,717 185,543 127
Distributions to
non-controlling
interests (26,568) (3,552) 648 (51,433) (7,139) 620
Cash retained for
financing and
investing
activities (123,257) (14,715) 738 (187,505) (21,897) 756
----------------------------------------------------------------------------
Distributions to
unitholders 91,662 80,236 14 182,779 156,507 17

Accumulated cash
distributions,
beginning of
period 1,351,294 1,003,096 35 1,260,177 926,825 36
----------------------------------------------------------------------------
Accumulated cash
distributions,
end of period $1,442,956 $1,083,332 33 $1,442,956 $1,083,332 33
----------------------------------------------------------------------------
Cash distributions
per unit $ 0.36 $ 0.36 - $ 0.72 $ 0.72 -
----------------------------------------------------------------------------
----------------------------------------------------------------------------

Taxes
Three months Six months
ended June 30, ended June 30,
----------------------------------------------------------------------------
% %
($ 000s) 2008 2007 Change 2008 2007 Change
----------------------------------------------------------------------------
Capital tax
expense $ 1,210 $ 630 92 $ 1,692 $ 888 91
Current and
withholding
tax (recovery)
expense (1,211) (1,660) (27) 3,824 2,898 32
Future income
tax (recovery)
expense (71,554) 74,439 - (103,555) 63,606 -
----------------------------------------------------------------------------
$ (71,555) $ 73,409 - $ (98,039) $ 67,392 -
----------------------------------------------------------------------------
----------------------------------------------------------------------------


For the six months ended June 30, 2008, the total income tax recovery was $98.0 million. Based on year-to-date loss before taxes of $334.2 million, the expected income tax recovery was $89.2 million. The difference between the expected recovery and the total tax recovery 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 until 2011, when the new tax on distributions comes into effect. 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.

Capital taxes in the second quarter totaled $1.2 million, an increase from the $0.6 million expense recorded in the second quarter of 2007, and $1.7 million year-to-date, compared to $0.9 million year-to-date for 2007. The increase is due to greater production subject to the Saskatchewan resource surcharge.

The current and withholding tax recovery of $1.2 million in the second quarter of 2008 compares to a recovery of $1.7 million in the second quarter of 2007. For the six months ended June 30, 2008, current and withholding tax expense was $3.8 million, compared with $2.9 million in 2007. These taxes arise from the Midstream operations.

The 2008 second quarter future income tax recovery of $71.6 million compares to an expense of $74.4 million in the second quarter of 2007. The recovery in 2008 is primarily a result of increased tax loss carry-forwards generated from interest and royalties charged by the Trust to its subsidiaries. The expense in 2007 includes $104.7 million resulting from the enactment of legislation to tax publicly traded trusts, including Provident, commencing in 2011. For the six months ended June 30, 2008, future income tax recovery was $103.5 million compared with an expense of $63.6 million in 2007.



Interest expense

Three months Six months
Continuing operations ended June 30, ended June 30,
----------------------------------------------------------------------------
($ 000s, except % %
as noted) 2008 2007 Change 2008 2007 Change
----------------------------------------------------------------------------
Interest on bank
debt $ 10,834 $ 7,764 40 $ 23,393 $ 16,672 40
Interest on
convertible
debentures 4,984 5,103 (2) 9,968 10,200 (2)
Discontinued
operations
portion (2,091) (2,109) (1) (4,185) (4,214) (1)
----------------------------------------------------------------------------
Total cash
interest $ 13,727 $ 10,758 28 $ 29,176 $ 22,658 29
----------------------------------------------------------------------------
----------------------------------------------------------------------------

Weighted average
interest rate on
all long-term
debt 5.1% 5.7% (11) 5.4% 5.7% (5)
Debenture accretion
and other non-cash
interest expense 1,106 1,188 (7) 2,312 2,403 (4)
----------------------------------------------------------------------------
Total interest
expense $ 14,833 $ 11,946 24 $ 31,488 $ 25,061 26
----------------------------------------------------------------------------
----------------------------------------------------------------------------


Interest on bank debt increased in 2008 compared to 2007 due to increased capitalization including debt levels, largely resulting from the Capitol acquisition in the second quarter of 2007.

Commodity price risk management program

Provident's commodity price risk management program is intended to mitigate 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 to reduce its exposure to fluctuations in commodity prices and foreign exchange rates.

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

In the Midstream business, production margins are affected by the spread between the purchase cost of natural gas and sales price of propane, butane and condensate. Market conditions have not provided sufficient or adequate opportunity to directly manage propane, butane and condensate prices over the longer term. Prices for propane, butane and condensate historically have correlated with prices for crude oil. As a consequence, Provident has entered into natural gas, natural gasoline and crude oil financial derivative contracts through March 2013 in order to protect operating margins in the Midstream business. Short term financial derivative instruments directly fixing propane prices have also been executed.

Activity in the Second Quarter

A summary of Provident's risk management contracts executed during the second quarter of 2008 from continuing operations is contained in the following tables:



COGP

Volume
Year Product (Buy)/Sell Terms Effective Period
----------------------------------------------------------------------------
Natural November 1 -
2008 Gas 4,000 Gjpd Puts Cdn $9.26 per gj (2) December 31
Natural January 1 -
2009 Gas 4,000 Gjpd Puts Cdn $9.26 per gj (2) March 31
----------------------------------------------------------------------------
----------------------------------------------------------------------------

Midstream


Volume
Year Product (Buy)/Sell Terms Effective Period
----------------------------------------------------------------------------
2008 Natural July 1 -
Gas 2,500 Gjpd Cdn $10.79 per gj (2)(7) July 31
Crude August 1 -
Oil 817 Bpd US $136.00 per bbl (3)(8) December 31
July 1 -
565 Bpd Cdn $126.60 per bbl (3)(7) August 31
Natural August 1 -
Gasoline(817) Bpd US $2.895 per gallon (6)(8) December 31
July 1 -
Propane 1,658 Bpd US $1.7534 per gallon (5)(7) December 31

2009 Crude January 1 -
Oil 825 Bpd US $136.00 per bbl (3)(8) December 31
Natural January 1 -
Gasoline(825) Bpd US $2.895 per gallon (6)(8) December 31
----------------------------------------------------------------------------
----------------------------------------------------------------------------

Corporate

Volume
Year Product (Buy)/Sell Terms Effective Period
----------------------------------------------------------------------------
2008 Foreign Buy US $103,500,000 per month @
exchange 1.0203 (4) September 15, 2008
Buy US $ 34,500,000 per month @
1.0205 (4) December 15, 2008
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(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) Forward purchase of US dollars.
(5) Propane contracts are settled against Belvieu C3 TET.
(6) Natural Gasoline contracts are settled against Belvieu NON-TET Natural
Gasoline.
(7) Midstream inventory hedges.
(8) Midstream margin condensate hedges.


A summary of all of Provident's contracts in place at June 30, 2008 is available on Provident's website at www.providentenergy.com.

Settlement of commodity contracts

The following is a summary of the net funds flow from operations to settle commodity contracts (related to continuing operations) during the second quarter and first six months of 2008. For comparative purposes the 2007 amounts are also summarized.

a) Crude oil -COGP

For the quarter ended June 30, 2008, Provident paid $7.3 million to settle various oil market based contracts on an aggregate volume of 0.4 million barrels. During the quarter ended June 30, 2007, Provident paid $0.8 million to settle various oil market based contracts on an aggregate volume of 0.3 million barrels. Strong oil prices during the quarter caused the opportunity cost on oil price risk management activities.

For the six months ended June 30, 2008, Provident paid $11.2 million to settle various oil based contracts on an aggregate volume of 0.8 million barrels. During the six months ended June 30, 2007, Provident paid $0.8 million to settle various oil market based contracts on an aggregate volume of 0.5 million barrels.

If all contracts in place had been settled at June 30, 2008 an estimated opportunity cost of $41.3 million (June 30, 2007 - $5.3 million) would have been incurred.

b) Natural Gas - COGP

For the quarter ended June 30, 2008, Provident paid $2.0 million to settle various natural gas market based contracts on an aggregate volume of 2.7 million gj's. For comparison, during the three months ended June 30, 2007, Provident paid $0.6 million to settle various natural gas market based contracts on an aggregate volume of 3.8 million gj's.

For the six months ended June 30, 2008, Provident paid $1.0 million to settle various natural gas market based contracts on an aggregate volume of 6.3 million gj's. For comparison, during the six months ended June 30, 2007, Provident paid $1.4 million to settle various natural gas market based contracts on an aggregate volume of 7.6 million gj's.

If contracts in place had been settled at June 30, 2008 an estimated opportunity cost of $10.0 million (June 30, 2007 - $10.2 million gain) would have been incurred.

c) Midstream

For the quarter ended June 30, 2008, Provident paid $55.4 million (2007 - received $9.2 million) to settle Midstream oil market based contracts on an aggregate volume of 1.2 million barrels (2007 - 0.2 million barrels) and received $3.3 million (2007 - paid $7.9 million) to settle Midstream natural gas market based contracts on an aggregate volume of 6.6 million gj's (2007 - 6.8 million gj's). This net opportunity cost was primarily caused by record high crude oil prices. In addition, for the second quarter of 2008, Provident paid $3.2 million (2007 - $11.7 million) to settle Midstream NGL market based contracts on an aggregate volume of 0.1 million barrels (2007 - 1.1 million barrels).

For the six months ended June 30, 2008, Provident paid $69.8 million (2007 - received $12.5 million) to settle Midstream oil market based contracts on an aggregate volume of 1.4 million barrels (2007 - 0.5 million barrels) and paid $7.7 million (2007 - $12.4 million) to settle Midstream natural gas market based contracts on an aggregate volume of 13.4 million gj's (2007 - 11.9 million gj's). In addition, Provident paid $8.6 million (2007 - $12.6 million) to settle Midstream NGL market based contracts on an aggregate volume of 2.0 million barrels (2007 - 3.1 million barrels).

If contracts in place had been settled at June 30, 2008 an estimated opportunity cost of $694.7 million (June 30, 2007 - $69.0 million) would have been incurred. These unrealized "mark-to-market" opportunity costs relate to positions with effective periods ranging from 2008 through 2013 and are required to be recognized in the financial statements under generally accepted accounting principles. 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 funds flow from operations until the instrument is settled.

d) Foreign exchange contracts

For the quarter ended June 30, 2008, Provident received $2.7 million to settle various foreign exchange based contracts (2007 - nil). For the six months ended June 30, 2008, Provident received $5.5 million to settle various foreign exchange based contracts (2007 - nil). If contracts in place had been settled at June 30, 2008 an estimated opportunity cost of nil (June 30, 2007 - $1.0 million gain) would have been incurred.

e) Interest rate contracts

For the quarter and six months ended June 30, 2008, Provident paid $0.1 million to settle various interest rate based contracts (2007 - nil).

f) Power contracts

For the quarter and six months ended June 30, 2008, Provident received $1.4 million to settle various electricity based contracts (2007 - nil). It is estimated that if contracts in place had been settled at June 30, 2008 an opportunity gain of $2.0 million (2007 - nil) would have been realized.



Liquidity and capital resources

Continuing operations
----------------------------------------------------------------------------
June 30, December 31,
($ 000s) 2008 2007 % Change
----------------------------------------------------------------------------

Long-term debt - revolving
term credit facility $ 626,192 $ 923,996 (32)
Long-term debt - convertible
debentures (including current
portion) 278,269 275,638 1
Working capital deficit
(surplus) (1) 45,931 (58,732) -
----------------------------------------------------------------------------
Net debt 950,392 1,140,902 (17)
----------------------------------------------------------------------------
----------------------------------------------------------------------------

Unitholders' equity (at book
value) 1,443,755 1,708,665 (16)
----------------------------------------------------------------------------
Total capitalization at book
value $ 2,394,147 $ 2,849,567 (16)
----------------------------------------------------------------------------
----------------------------------------------------------------------------

Total net debt as a
percentage of total book
value capitalization 40% 40% -
----------------------------------------------------------------------------
----------------------------------------------------------------------------

(1) The working capital deficit (surplus) excludes balances for the current
portion of financial derivative instruments.


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

As at June 30, 2008, Provident held non-bank sponsored asset-backed commercial paper amounting to $4.6 million. These securities have been classified as investments due to a reduction in market liquidity for these investments. Provident does not expect the resolution of the liquidity issues to have a significant impact on its operations.

Long-term debt and working capital

As at June 30, 2008 Provident had drawn on 56 per cent of its Canadian term credit facility of $1,125 million. This compares to 81 per cent drawn as at December 31, 2007.

At June 30, 2008 Provident had letters of credit guaranteeing Provident's performance under certain commercial and other contracts that totaled $29.5 million, increasing bank line utilization to 58 per cent. The guarantees totaled $31.6 million at December 31, 2007.

Provident's working capital from continuing operations decreased by $244.7 million as at June 30, 2008 relative to December 31, 2007. This amount includes a $33.1 million increase in accounts payable and accrued liabilities, a $149.9 million increase in income taxes payable driven by taxes incurred on the sale of a portion of the USOGP business in the second quarter of 2008, a $139.6 million increase in the current portion of financial derivative instruments, partially offset by a $46.5 million increase in accounts receivable, a $27.1 million increase in inventory, and a $3.9 million increase in prepaid expenses and other current assets.

Second quarter funds flow from continuing operations in 2008 was $165.5 million. The ratio of net debt (as calculated under "Liquidity and capital resources") to annualized second quarter funds flow from continuing operations was 1.4 to one, as compared to second quarter 2007 net debt to annualized funds flow from continuing operations of 3.3 to one. The decreased ratio reflects a decrease in net debt as well as higher funds flow in both COGP and Midstream.

Trust units

For the quarter ended June 30, 2008, the Trust issued no units on conversion of convertible debentures (2007 - 35 thousand units). An additional 0.1 million units pursuant to the unit option plan were issued for the quarter ended June 30, 2008 (2007- 0.1 million units). Under Provident's Premium Distribution, Distribution Reinvestment (DRIP) and Optional Unit Purchase Plan program 1.3 million units were elected in the second quarter and were issued or are to be issued representing proceeds of $14.5 million (2007 - 0.8 million units for proceeds of $9.8 million).

At June 30, 2008, management and directors held less than one per cent of the outstanding units.



Capital expenditures and funding

Three months Six months
Continuing operations ended June 30, ended June 30,
----------------------------------------------------------------------------
% %
($ 000s) 2008 2007 Change 2008 2007 Change
----------------------------------------------------------------------------
Capital
Expenditures
Capital expenditures
and site
restoration
expenditures $(35,311) $ (27,884) 27 $(121,430) $ (67,863) 79
Property
acquisitions, net (10,432) (1,028) 915 (19,451) (9,709) 100
Corporate acquisitions - (467,850) (100) - (467,850) (100)
----------------------------------------------------------------------------
Net capital
expenditures $(45,743) $(496,762) (91) $(140,881) $(545,422) (74)
----------------------------------------------------------------------------

Funded By
Funds flow from
continuing operations
net of declared
distributions to
unitholders $ 73,808 $ 1,365 5,307 $ 113,085 $ 10,908 937
(Decrease) increase
in long-term debt (264,011) 156,735 - (298,576) 99,233 -
Issue of trust
units, net of cost;
excluding DRIP 1,197 355,811 (100) 1,204 360,647 (100)
DRIP proceeds 14,484 9,823 47 28,674 20,580 39
Change in working
capital, including
cash, sale of
assets and change
in investments 220,265 (26,972) - 296,494 54,054 449
----------------------------------------------------------------------------
Net capital
expenditure
funding $ 45,743 $ 496,762 (91) $ 140,881 $ 545,422 (74)
----------------------------------------------------------------------------
----------------------------------------------------------------------------


For the comparable quarters Provident has funded its net capital expenditures with funds flow from operations, debt and equity issued from treasury through public offerings and the DRIP (Distribution Re-Investment Program), and the sale of assets.

Non-cash unit based compensation

Non-cash unit based compensation includes expenses associated with Provident's restricted and performance unit plan, as well as the unit option plan. Provident accounts for the unit option plan using the fair value of the option at the time of issue. The other unit based compensation is recorded at the estimated fair value of the notional units granted. Compensation expense associated with the plans is recognized in earnings over the vesting period of each plan. The expense associated with each period is recorded as non-cash unit based compensation (a component of general and administrative expense). A portion relating to operational employees at field and plant locations is also allocated to operating expense. Provident recorded unit based compensation expense of $4.9 million for the quarter ended June 30, 2008 (2007 - $4.7 million) included primarily in general and administrative expense. Provident made no payments in respect of unit based compensation in the second quarter of 2008 (2007 - nil). For the six months ended June 30, 2008, Provident recorded unit based compensation expense of $10.2 million (2007 - $9.1 million) and made related cash payments of $8.3 million (2007 - $1.8 million). At June 30, 2008, the current portion of the liability totaled $18.9 million (December 31, 2007 - $9.9 million) and the long-term portion totaled $4.9 million (December 31, 2007 - $12.4 million).



COGP segment review

Crude oil and liquids price

The following prices are net of transportation expense.

Three months Six months
COGP ended June 30, ended June 30,
----------------------------------------------------------------------------
% %
($ per bbl) 2008 2007 Change 2008 2007 Change
----------------------------------------------------------------------------

Oil per barrel
WTI (US$) $ 123.98 $ 65.03 91 $ 110.94 $ 61.60 80
Exchange rate
(from US$ to Cdn$) $ 1.01 $ 1.10 (8) $ 1.01 $ 1.13 (11)
WTI expressed in
Cdn$ $ 125.22 $ 71.42 75 $ 111.72 $ 69.90 60
----------------------------------------------------------------------------
----------------------------------------------------------------------------

Realized pricing
before financial
derivative
instruments
Crude oil $ 105.13 $ 53.75 96 $ 90.22 $ 52.54 72
Natural gas liquids $ 94.59 $ 52.79 79 $ 83.15 $ 50.84 64
----------------------------------------------------------------------------
Crude oil and
natural gas
liquids $ 104.22 $ 53.63 94 $ 89.57 $ 52.30 71
----------------------------------------------------------------------------
----------------------------------------------------------------------------


In the second quarter of 2008, COGP's realized crude oil and natural gas liquids price, prior to the impact of financial derivative instruments, increased by 94 per cent to $104.22 per barrel compared to $53.63 in the second quarter of 2007. The 2008 increase was a result of a 91 per cent increase in $US WTI crude oil price combined with narrower price differentials relative to WTI, partially offset by a stronger Canadian dollar.



Natural gas price

The following prices are net of transportation expense.

Three months Six months
COGP ended June 30, ended June 30,
----------------------------------------------------------------------------
% %
($ per mcf) 2008 2007 Change 2008 2007 Change
----------------------------------------------------------------------------
AECO monthly index
(Cdn$ per mcf) $ 9.35 $ 7.37 27 $ 8.24 $ 7.38 12
Corporate natural
gas price per mcf
before financial
derivative
instruments (Cdn$) $ 9.98 $ 7.27 37 $ 8.81 $ 7.37 20
----------------------------------------------------------------------------
----------------------------------------------------------------------------


COGP's second quarter 2008 realized natural gas price, before financial derivative instruments, increased 37 per cent as compared to the second quarter of 2007, which was 10 per cent greater than the increase in the AECO monthly index over the same period. Provident markets to aggregators and can sell to the market on daily and monthly indices, receiving prices which 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

Three months Six months
COGP ended June 30, ended June 30,
----------------------------------------------------------------------------
% %
2008 2007 Change 2008 2007 Change
----------------------------------------------------------------------------
Daily production
Crude oil (bpd) 12,494 8,610 45 12,390 8,354 48
Natural gas liquids
(bpd) 1,178 1,311 (10) 1,243 1,366 (9)
Natural gas (mcfd) 86,130 94,437 (9) 85,050 91,698 (7)
----------------------------------------------------------------------------
Oil equivalent
(boed) (1) 28,027 25,660 9 27,808 25,003 11
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(1) Provident reports equivalent production converting natural gas to oil
on a 6:1 basis


Production increased nine per cent to 28,027 boed during the second quarter of 2008 as compared to 25,660 boed in the comparable 2007 quarter. The increase in production was primarily a result of the Capitol and Triwest acquisitions, and drilling and development programs which were partially offset by natural production declines. Production for the second quarter of 2008 was weighted 51 per cent natural gas, and 49 per cent crude oil and natural gas liquids, a change from the 61 per cent natural gas, and 39 per cent crude oil and natural gas liquids for the second quarter of 2007. The change in the production weighting reflects the oil-weighted acquisitions completed in 2007 and their associated drilling programs. Production over the six months ended June 30, 2008 was weighted 51 per cent natural gas, and 49 per cent crude oil and natural gas liquids, a change from the 61 per cent natural gas, and 39 per cent crude oil and natural gas liquids for the six months ended June 30, 2007.

In the second quarter of 2008, the nine per cent production increase compared to the prior year's quarter was achieved despite production downtime primarily due to wet weather and natural gas plant turnarounds. Areas affected included West Central Alberta, Northwest Alberta, and Dixonville. In addition, commingling application delays in our shallow gas play in Southwest Saskatchewan continue to delay recompletions in this area. Production in Southeast Saskatchewan has increased reflecting the Triwest acquisition volumes and the associated drilling program. Dixonville production for the second quarter of 2007 only included the production from the date of the Capitol acquisition on June 19, 2007.



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

Three months Six months
ended June 30, ended June 30,
----------------------------------------------------------------------------
% %
COGP 2008 2007 Change 2008 2007 Change
----------------------------------------------------------------------------
Daily Production
- by area (boed) (1)
West Central Alberta 6,275 7,563 (17) 6,433 7,335 (12)
Southern Alberta 4,868 5,504 (12) 4,805 5,731 (16)
Northwest Alberta 4,925 5,253 (6) 4,783 4,923 (3)
Dixonville (2) 3,548 461 670 3,725 232 1,506
Southeast Saskatchewan 3,345 1,624 106 3,226 1,645 96
Southwest Saskatchewan 1,353 1,806 (25) 1,408 1,832 (23)
Lloydminster 3,713 3,449 8 3,428 3,305 4
----------------------------------------------------------------------------
28,027 25,660 9 27,808 25,003 11
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(1) Provident reports equivalent production converting natural gas to oil
on a 6:1 basis.

(2) Dixonville production in 2007 represents production from June 19, 2007
(date of Capitol Energy Resources Ltd. Acquisition) amounting to 3,815
boed for the 11 days.


Revenue and royalties

Three months Six months
COGP ended June 30, ended June 30,
----------------------------------------------------------------------------
($ 000s except per % %
boe and mcf data) 2008 2007 Change 2008 2007 Change
----------------------------------------------------------------------------

Oil

Revenue $ 119,525 $ 42,111 184 $ 203,448 $ 79,447 156

Realized loss on
financial
derivative
instruments (7,333) (768) 855 (11,262) (755) 1,392
Royalties (22,721) (8,250) 175 (37,794) (15,362) 146
----------------------------------------------------------------------------
Net revenue $ 89,471 $ 33,093 170 $ 154,392 $ 63,330 144
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Net revenue
(per barrel) $ 78.69 $ 42.24 86 $ 68.47 $ 41.88 63
Royalties as a
percentage of
revenue 19.0% 19.6% 18.6% 19.3%

Natural gas

Revenue $ 78,198 $ 62,464 25 $ 136,350 $ 122,344 11

Realized loss on
financial
derivative
instruments (1,921) (575) 234 (966) (1,433) (33)
Royalties (13,506) (11,188) 21 (24,790) (22,055) 12
----------------------------------------------------------------------------
Net revenue $ 62,771 $ 50,701 24 $ 110,594 $ 98,856 12
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Net revenue
(per mcf) $ 8.01 $ 5.90 36 $ 7.14 $ 5.96 20
Royalties as a
percentage of
revenue 17.3% 17.9% 18.2% 18.0%

Natural gas liquids

Revenue $ 10,139 $ 6,297 61 $ 18,806 $ 12,570 50
Royalties (2,459) (1,649) 49 (4,699) (3,355) 40
----------------------------------------------------------------------------
Net revenue $ 7,680 $ 4,648 65 $ 14,107 $ 9,215 53
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Net revenue
(per barrel) $ 71.64 $ 38.98 84 $ 62.38 $ 37.27 67
Royalties as a
percentage of
revenue 24.2% 26.2% 25.0% 26.7%

Total

Revenue $ 207,862 $ 110,872 87 $ 358,604 $ 214,361 67
Realized loss on
financial
derivative
instruments (9,254) (1,343) 589 (12,228) (2,188) 459
Royalties (38,686) (21,087) 83 (67,283) (40,772) 65
----------------------------------------------------------------------------
Net revenue $ 159,922 $ 88,442 81 $ 279,093 $ 171,401 63
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Net revenue
(per boe) $ 62.70 $ 37.87 66 $ 55.15 $ 37.87 46
Royalties as a
percentage of
revenue 18.6% 19.0% 18.8% 19.0%
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Note: the above revenue, net revenue and net revenue per boe figures are
presented net of transportation expenses.


Quarter over quarter, 2008 COGP net revenue increased by 81 per cent to $159.9 million and by 66 per cent to $62.70 per boe. The increases reflect increases in crude oil production and increases in realized crude oil, natural gas liquids, and natural gas prices. Royalties, which are price sensitive and affected by production levels stayed constant as a percentage of revenue in the second quarter of 2008, compared to the second quarter in 2007. The increase in realized loss on financial derivative instruments to $9.2 million in the second quarter of 2008 from $1.3 million in the comparable 2007 quarter reflects a $1.9 million loss on natural gas derivative contracts in 2008 combined with a $7.3 million loss on oil derivative contracts in a record high crude oil price environment. For the six months ended June 30, 2008, net revenue per boe was $55.15 or 46 per cent above $37.87 in the same period of 2007.



Production expenses

Three months Six months
COGP ended June 30, ended June 30,
----------------------------------------------------------------------------
($ 000s, except % %
per boe data) 2008 2007 Change 2008 2007 Change
----------------------------------------------------------------------------
Production expenses $ 35,558 $ 25,104 42 $ 65,934 $ 51,365 28
Production expenses
(per boe) $ 13.94 $ 10.75 30 $ 13.03 $ 11.35 15
----------------------------------------------------------------------------
----------------------------------------------------------------------------


Second quarter 2008 production expenses increased to $35.6 million from $25.1 million in the comparable 2007 quarter. The increase was due to the nine per cent increase in quarter over quarter production, and COGP returning wells with higher operating costs to production to take advantage of higher netbacks resulting from the current pricing environment. As well, the increased commodity prices raised prices for fuel consumption and power, and increased costs in service related activities for down-hole and maintenance work. On a per boe basis, production expenses increased to $13.94 per boe compared to $10.75 per boe in the second quarter of 2007. The per boe production expenses includes the impact of the decision to return higher cost wells to production as well as additional costs due to unexpected wet weather events including road bans which increased hauling costs and higher natural gas plant turnaround costs, further compounded by the associated lost production during the turnarounds.

Year-to-date production expenses increased 28 per cent to $65.9 million from $51.4 million in 2007, reflecting the 11 per cent increase in production, the higher cost environment and the return to production of wells with higher operating costs to take advantage of the higher netbacks resulting from the current price environment.



Operating netback

Three months Six months
COGP ended June 30, ended June 30,
----------------------------------------------------------------------------
% %
($ per boe) 2008 2007 Change 2008 2007 Change
----------------------------------------------------------------------------
Netback per boe
Gross production
revenue $ 81.50 $ 47.48 72 $ 70.86 $ 47.36 50
Royalties (15.17) (9.03) 68 (13.29) (9.01) 48
Operating costs (13.94) (10.75) 30 (13.03) (11.35) 15
----------------------------------------------------------------------------
Field operating
netback 52.39 27.70 89 44.54 27.00 65
Realized loss on
financial
derivative
instruments (3.63) (0.58) 526 (2.42) (0.48) 404
----------------------------------------------------------------------------
Operating netback
after realized
financial
derivative
instruments $ 48.76 $ 27.12 80 $ 42.12 $ 26.52 59
----------------------------------------------------------------------------
----------------------------------------------------------------------------


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

Second quarter 2008 field operating netback increased 89 per cent to $52.39 per boe from $27.70 per boe in the comparable 2007 quarter. Year-to-date field operating netback of $44.54 per boe was 65 per cent above the field operating netback for the same period in 2007. The increase in field operating netback reflects a higher production weighting to crude oil accompanied by an increase in realized crude oil, natural gas liquids, and natural gas prices. Royalties on a per boe basis increased due to the increase in realized commodity prices, whereas royalties as a percentage of revenue was consistent with the prior year. Operating netbacks after realized financial derivative instruments increased by 80 per cent to $48.76 per boe from $27.12 per boe for the quarter, reflecting a realized loss on financial derivative instruments of $3.63 per boe compared to $0.58 per boe realized loss in the comparable quarter in 2007. The realized loss is primarily from oil derivative contracts in a record high crude oil price environment.



General and administrative

Three months Six months
COGP ended June 30, ended June 30,
----------------------------------------------------------------------------
($000s, except % %
per boe data) 2008 2007 Change 2008 2007 Change
----------------------------------------------------------------------------
Cash general and
administrative $ 7,828 $ 7,883 (1) $ 19,751 $ 15,120 31
Non-cash unit
based compensation 2,550 2,025 26 805 3,011 (73)
----------------------------------------------------------------------------
$ 10,378 $ 9,908 5 $ 20,556 $ 18,131 13
Cash general and
administrative
(per boe) $ 3.07 $ 3.38 (9) $ 3.90 $ 3.34 17
----------------------------------------------------------------------------
----------------------------------------------------------------------------


Second quarter 2008 COGP cash general and administrative expenses decreased one per cent to $7.8 million compared to $7.9 million in the second quarter of 2007. On a per barrel basis, cash general and administrative expenses decreased nine per cent to $3.07 per boe in 2008 compared to the $3.38 per boe in the second quarter of 2007. The per boe decrease reflects the nine per cent increase in production, without a commensurate increase in general and administrative costs.

For the six months ended June 30, 2008, COGP cash general and administrative expenses increased 31 per cent to $19.8 million (2007 - $15.1 million). On a per barrel basis, cash general and administrative expenses increased 17 per cent to $3.90 per boe in 2008 compared to the $3.34 per boe in the six months ended June 30, 2007. For the six months ended June 30, 2008, cash general and administrative expense includes $4.5 million or $0.89 per boe (2007 - $0.9 million or $0.20 per boe) related to payments associated with performance unit based compensation. The unit based expense was accrued over a three-year vesting period as non-cash unit based compensation, consequently there is an offsetting reduction in non-cash unit based compensation in 2008, when the payments were made. Non-cash unit based compensation for the six months ended June 30, 2008 decreased to $0.8 million (2007 - $3.0 million). Excluding the related cash payments in the periods, non-cash unit based compensation was $5.3 million in the six months ended June 30, 2008 (2007 - $3.9 million).



Capital expenditures

Three months Six months
COGP ended June 30, ended June 30,
----------------------------------------------------------------------------
----------------------------------------------------------------------------
($ 000s) 2008 2007 2008 2007
----------------------------------------------------------------------------

Capital expenditures - by category
Geological, geophysical and land $ 721 $ 1,297 $ 3,703 $ 2,081
Drilling and recompletions 19,596 15,163 80,284 48,626
Facilities and equipment 6,296 1,510 18,107 4,768
Other capital 1,878 3,646 5,555 4,529
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Total additions $ 28,491 $ 21,616 $107,649 $ 60,004
----------------------------------------------------------------------------
----------------------------------------------------------------------------

Capital expenditures - by area
West central Alberta $ 1,718 $ 1,877 $ 5,160 $ 4,593
Southern Alberta 3,150 2,972 6,873 6,490
Northwest Alberta 5,420 5,410 40,961 27,303
Dixonville 11,046 1,803 30,741 1,803
Southeast Saskatchewan 1,990 435 9,328 857
Southwest Saskatchewan 851 2,566 2,892 10,606
Lloydminster 2,563 2,723 5,307 3,695
Office and other 1,753 3,830 6,387 4,657
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Total additions $ 28,491 $ 21,616 $ 107,649 $ 60,004
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Property acquisitions, net $ 10,432 $ 1,028 $ 19,451 $ 9,709
----------------------------------------------------------------------------
----------------------------------------------------------------------------


In the second quarter of 2008, COGP continued the successful execution of its capital program throughout its core areas. The COGP business unit spent $19.6 million relating to drilling and recompletion activities, drilling 11.5 net wells with 100 per cent success. Capital activity in COGP's newest core area, Dixonville, the winter program in Northwest Alberta and drilling in Southeast Saskatchewan account for 65 per cent of COGP's capital expenditures in the second quarter of 2008.

At Dixonville, $11.0 million was spent primarily on drilling and completion activities, which included 8.0 net wells drilled. In Northwest Alberta, completion expenditures of $5.4 million related to the 2007/2008 winter capital program were primarily spent on additional facility work. The $12.1 million of capital spent in the remaining core areas included drilling, completion, tie-ins, recompletions, facility upgrades and production optimization activities.

Net property acquisitions of $19.5 million in 2008 include additional working interests in the Triwest assets in Southeast Saskatchewan, which were acquired in December 2007.



Depletion, depreciation and accretion (DD&A)

Three months Six months
COGP ended June 30, ended June 30,
----------------------------------------------------------------------------
($000s, except % %
per boe data) 2008 2007 Change 2008 2007 Change
----------------------------------------------------------------------------

DD&A $ 75,423 $ 58,272 29 $ 147,925 $ 113,570 30
DD&A (per boe) $ 29.57 $ 24.96 18 $ 29.23 $ 25.10 16
----------------------------------------------------------------------------
----------------------------------------------------------------------------


The COGP DD&A rate of $29.57 per boe for the second quarter of 2008 increased by 18 per cent compared to $24.96 per boe for the second quarter of 2007. The increase was primarily as a result of the two acquisitions of Capitol and Triwest in 2007. These recent COGP acquisitions and the Rainbow assets acquired in 2005 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 not yet proved reserves generally result in higher depletion rates. The impact of this, combined with the higher cost of acquiring or drilling proved reserves in western Canada in an environment with higher commodity prices and increased drilling costs, will be reflected in the DD&A rate going forward.

In the second quarter of 2008, accretion expense associated with asset retirement obligations was $0.8 million compared to $0.6 million in the comparable period of 2007. Year-to-date accretion expense was $1.7 million (2007 - $1.2 million).

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 Six months
ended June 30, ended June 30,
----------------------------------------------------------------------------
% %
($ 000s) 2008 2007 Change 2008 2007 Change
----------------------------------------------------------------------------

Empress East Margin $ 48,059 $ 33,013 46 $ 114,539 $ 64,279 78
Redwater West Margin 60,063 11,448 425 100,351 28,970 246
Commercial Services
Margin 11,624 11,035 5 22,182 24,157 (8)
----------------------------------------------------------------------------
Gross operating
margin 119,746 55,496 116 237,072 117,406 102
Realized loss on
financial
derivative
instruments (51,317) (10,397) 394 (79,280) (12,486) 535
Cash general and
administrative
expenses (7,627) (9,125) (16) (19,486) (16,093) 21
Foreign exchange
gain (loss) and other 967 - - (550) - -
----------------------------------------------------------------------------
Midstream EBITDA $ 61,769 $ 35,974 72 $ 137,756 $ 88,827 55
----------------------------------------------------------------------------
----------------------------------------------------------------------------


Gross operating margin

The Empress East business line:

The Empress East business line extracts NGLs from natural gas at the Empress straddle plants and sells finished products into markets in Central Canada and the Eastern United States. The margin in this business is determined primarily by the "frac spread ratio", which is the ratio between crude oil prices and natural gas prices. Traditionally, the higher the ratio, the better this business line will perform. There is also a differential between propane, butane and condensate (collectively, these products are referred to as "propane-plus") prices and crude oil prices which can change prices received and margins realized for Midstream products separate from frac spread ratio changes. In the second quarter of 2008, the margin for this business line was $48.1 million (2007 - $33.0 million). This 46 per cent increase is the result of approximately 50 per cent higher propane-plus prices while costs only increased approximately 45 per cent. This increased margin reflects higher selling prices partially offset by a six per cent decrease in related sales volumes. The year-to-date margin was $114.5 million in 2008 compared to year-to-date margin of $64.3 million in 2007. The year-to-date 78 per cent increase in margin is the result of approximately 40 per cent higher propane-plus prices while per-unit cost of goods sold only increased approximately 30 per cent. The higher propane-plus prices reflect the stronger WTI crude oil price in 2008. The margins reflect a cost of goods sold per unit increase that was significantly less than sales price per unit as a result of the natural gas prices which were lower in relation to crude oil prices in 2008, when compared to 2007. As a result, the frac spread ratio was higher in 2008.

The Redwater West business line:

The Redwater West business line purchases an NGL mix from various producers and fractionates it into finished products at the Redwater fractionation facility near Edmonton, Alberta. Because the feedstock for this business line is primarily NGL mix rather than natural gas, the frac spread ratio has a smaller impact on margin than in the Empress East business line. This facility also has the largest rail rack in Western Canada to receive products for delivery into the local condensate market. Provident has considerably increased its participation in the condensate market over the past year, reflecting the increasing diluent demand for heavy oil production. In the second quarter of 2008, the margin for the Redwater West business line was $60.1 million (2007 - $11.5 million). The $48.6 million increase reflects approximately 20 per cent higher propane-plus sales volumes, primarily condensate. Provident made effective use of its transportation and storage assets to increase condensate sales in the quarter. In addition, propane-plus prices were 65 per cent higher in the second quarter of 2008 than in the second quarter of 2007 while costs were only 50 per cent higher. The higher propane-plus prices reflect the stronger crude oil price in the second quarter of 2008. Year-to-date margin increased to $100.4 million from $28.9 million in 2007. Sales volumes in 2008 have increased 20 per cent, primarily relating to condensate. Additionally, per-unit selling prices increased approximately 50 per cent and per-unit cost of goods sold only increased approximately 40 per cent.

The Commercial Services business line:

The Commercial Services business line generates income from relatively 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 second quarter of 2008, the margin for this business line was $11.6 million (2007 - $11.0 million). The five per cent increase in the margin is due primarily to increases in loading/unloading revenue partially offset by reduced third party fractionation revenue. Year-to-date 2008, the commercial services margin was $22.2 million (2007 - $24.2 million). This decrease is due to reduced third party fractionation revenue and reduced pipeline revenue offset by increased loading/unloading revenues.

Operations - Midstream NGL sales volumes

Midstream sold 110,826 bpd in the second quarter of 2008, relatively unchanged when compared with 109,713 bpd in the second quarter of 2007. Year-to-date Midstream sold 123,573 bpd in 2008, up five per cent when compared to sales of 117,331 bpd in 2007.

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

Second quarter 2008 EBITDA increased to $61.8 million from $36.0 million in 2007 reflecting higher operating margins for both the Empress East and Redwater West business lines, partially offset by higher realized losses on financial derivative instruments. Year-to-date EBITDA increased to $137.8 million from $88.8 million in 2007. Funds flow from operations for the second quarter of 2008 was $52.6 million, an increase of $23.0 million or 78 per cent above the $29.6 million for the second quarter 2007. Year-to-date funds flow from operations increased to $111.9 million from $69.0 million in 2007. The increase in funds flow from operations reflects the higher EBITDA and operating margins, as described above.

Cash general and administrative expenses and other were $7.6 million for the second quarter of 2008 (2007 - $9.1 million). The decrease reflects lower provision for short-term incentive compensation in 2008.

Cash general and administrative expenses and other were $19.5 million for the six months ended June 30, 2008 (2007 - $16.1 million). Year-to-date cash general and administrative expenses include $3.8 million (2007 - $0.9 million) related to payments associated with performance unit-based compensation. The expense was accrued over the three-year vesting period as non-cash unit based compensation, consequently there is an offsetting reduction in non-cash unit based compensation in 2008, when the payments were made.

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 second quarter of 2008 totaled $5.7 million, and $11.1 million year-to-date. In 2008, $4.2 million was spent on continued development of product storage, $4.8 million was spent on sustaining capital requirements and $2.1 million was spent primarily on office furniture and equipment for the new office space.

Discontinued operations (USOGP)

In February 2008, the Trust announced a strategic process respecting the decision to sell the operations that comprise the United States oil and natural gas production (USOGP) business. This business was comprised of approximately 22 per cent ownership of BreitBurn Energy Partners, L.P., a publicly-traded U.S. Master Limited Partnership ("the MLP"). This MLP ownership also included units held by the General Partner of which Provident owned approximately 96 per cent. As at June 30, 2008, Provident owned approximately 96 per cent of privately held BreitBurn Energy Company L.P. ("BreitBurn") which operates assets in California.

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

In June, 2008 Provident sold a portion of the USOGP business, consisting of its 22 per cent interest in the MLP and its 96 per cent interest in BreitBurn GP LLC, for cash proceeds, net of transaction costs, of U.S. $342.2 million. The Trust has recorded a gain on sale of $187.9 million and $141.8 million in current tax expense, related to this transaction. The future income tax recovery related to the MLP for the six months ended June 30, 2008 was $91.6 million. Also recorded was a realized foreign exchange loss of $30.3 million, representing the recognition of the related portion of the foreign exchange loss in accumulated other comprehensive income, which was generated since acquisition in 2006. These amounts are recorded as part of net income from discontinued operations for the three and six months ended June 30, 2008.

In July, 2008 the Trust announced an agreement to sell the remaining portion of the USOGP business, comprised of an approximate 96 per cent interest in BreitBurn, for total consideration of U.S. $305 million, consisting of cash proceeds of U.S. $295 million and a U.S. $10 million note. The transaction is expected to close prior to the end of August with proceeds initially applied to Provident's Canadian credit facility.

The pre-tax book value of the USOGP investments at June 30, 2008 was approximately $215 million and the related tax basis was approximately $100 million.



Distributions

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

Distribution Amount
Record Date Payment Date (Cdn$) (US$)(1)
----------------------------------------------------------------------------
2008
January 24, 2008 February 15, 2008 $ 0.12 0.12
February 25, 2008 March 14, 2008 0.12 0.12
March 24, 2008 April 15, 2008 0.12 0.12
April 22, 2008 May 15, 2008 0.12 0.12
May 23, 2008 June 13, 2008 0.12 0.12
June 20, 2008 July 15, 2008 0.12 0.12
----------------------------------------------------------------------------
2008 Cash Distributions paid as
declared $ 0.72 0.72
----------------------------------------------------------------------------
----------------------------------------------------------------------------
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 June 30, 2008 -
Distributions paid as declared $ 13.11 10.03
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(1) Exchange rate based on the Bank of Canada noon rate on the payment date.


Foreign ownership

As at June 30, 2008, based on information received from the transfer agent and financial intermediaries, an estimated 85 per cent of Provident's 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 security 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 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 assets 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.

Change in accounting policies

The interim consolidated financial statements have been prepared based on the consistent application of the accounting policies and procedures as set out in the consolidated financial statements of the Trust for the year ended December 31, 2007 and are consistent with policies adopted in the second quarter of 2007, except as described in note 2 of the interim consolidated financial statements.

In 2006, the Accounting Standards Board adopted a strategic plan for the direction of accounting standards in Canada. Accounting standards for public companies in Canada will converge with International Financial Reporting Standards (IFRS) by 2011 and Provident will be required to report according to IFRS standards for the year ended December 31, 2011. Provident is currently assessing the impact of the convergence of Canadian GAAP and IFRS on results of operations, financial position and disclosures.

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 funds flow from operations 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 funds flow from operations 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;

- regulatory intervention in determining processing fees and tariffs; and

- reliance on significant customers.

Provident strives to minimize these business risks by:

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

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

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

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

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

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

- maintaining a low cost structure to maximize funds flow from operations 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 quarter in the six months ended June 30, 2008 on both the Toronto Stock Exchange and the New York Stock Exchange:



Q1 Q2
----------------------------------------------------------------------------
TSE - PVE.UN (Cdn$)
High $ 11.37 $ 12.25
Low $ 8.80 $ 10.76
Close $ 10.95 $ 11.74
Volume (000s) 34,702 28,161
----------------------------------------------------------------------------
NYSE - PVX (US$)
High $ 11.28 $ 12.40
Low $ 8.50 $ 10.50
Close $ 10.60 $ 11.43
Volume (000s) 74,533 77,141
----------------------------------------------------------------------------
----------------------------------------------------------------------------


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.



Segmented information by quarter
----------------------------------------------------------------------------
($ 000s except for per unit and operating amounts) 2008
----------------------------------------------------------------------------
First Second Year-to-
Quarter Quarter Date
----------------------------------------------------------------------------
Financial - consolidated
Revenue (continuing operations) $ 702,215 $ 420,220 $ 1,122,435
Funds flow from operations $ 180,230 $ 241,487 $ 421,717
Net income (loss) $ 33,616 $ (184,081) $ (150,465)
Net income per unit - basic
and diluted $ 0.13 $ (0.72) $ (0.59)
Unitholder distributions $ 91,117 $ 91,662 $ 182,779
Distributions per unit $ 0.36 $ 0.36 $ 0.72
----------------------------------------------------------------------------

Oil and gas production
(continuing operations)
Cash revenue $ 122,815 $ 164,442 $ 287,257
Earnings before interest,
DD&A, taxes and other
non-cash items $ 75,348 $ 117,132 $ 192,480
Funds flow from operations $ 71,142 $ 112,869 $ 184,011
Net income $ 9,591 $ 28,935 $ 38,526
----------------------------------------------------------------------------

Midstream
Cash revenue $ 641,673 $ 662,315 $ 1,303,988
Earnings before interest, DD&A,
taxes and other non-cash items $ 75,987 $ 61,769 $ 137,756
Funds flow from operations $ 59,252 $ 52,601 $ 111,853
Net income (loss) $ 15,516 $ (290,230) $ (274,714)
----------------------------------------------------------------------------

Operating
Oil and gas production
(continuing operations)
Light/medium oil (bpd) 10,535 10,179 10,357
Heavy oil (bpd) 1,752 2,315 2,033
Natural gas liquids (bpd) 1,307 1,178 1,243
Natural gas (mcfd) 83,970 86,130 85,050
Oil equivalent (boed) 27,589 28,027 27,808
----------------------------------------------------------------------------

Average selling price net of
transportation expense
(continuing operations) (Cdn$)
Crude oil per bbl $ 75.06 $ 105.13 $ 90.22
(before realized financial
derivative instruments)
Crude oil per bbl $ 71.54 $ 98.68 $ 85.22
(including realized financial
derivative instruments)
Natural gas liquids per barrel $ 72.85 $ 94.59 $ 83.15
Natural gas per mcf $ 7.61 $ 9.98 $ 8.81
(before realized financial
derivative instruments)
Natural gas per mcf $ 7.74 $ 9.73 $ 8.75
(including realized financial
derivative instruments)
----------------------------------------------------------------------------

Midstream
Midstream NGL sales volumes (bpd) 136,320 110,826 123,573
----------------------------------------------------------------------------
----------------------------------------------------------------------------


Segmented information by quarter
----------------------------------------------------------------------------
($ 000s except for per unit
and operating amounts) 2007
----------------------------------------------------------------------------
First Second Third Fourth Annual
Quarter (1) Quarter (1) Quarter Quarter Total
----------------------------------------------------------------------------
Financial - consolidated
Revenue (continuing
operations) $ 558,807 $ 463,995 $494,065 $521,648 $ 2,038,515
Funds flow from
operations $ 87,040 $ 98,503 $105,149 $177,563 $ 468,255
Net income (loss) $ 43,093 $ (46,199)$(35,005)$ 68,545 $ 30,434
Net income (loss)
per unit - basic
and diluted $ 0.20 $ (0.21)$ (0.14)$ 0.28 $ 0.13
Unitholder
distributions $ 76,271 $ 80,236 $ 87,782 $ 89,063 $ 333,352
Distributions per
unit $ 0.36 $ 0.36 $ 0.36 $ 0.36 $ 1.44
----------------------------------------------------------------------------

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

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

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

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


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 (continuing
operations) $ 522,315 $ 398,225 $597,082 $505,556 $ 2,023,178
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
(continuing operations)
Cash revenue $ 78,343 $ 84,118 $ 75,766 $ 87,014 $ 325,241
Earnings before interest,
DD&A, taxes and other
non-cash items $ 47,615 $ 54,746 $ 45,335 $ 50,749 $ 198,445
Funds flow from
operations $ 39,949 $ 55,490 $ 41,315 $ 48,574 $ 185,328
Net income (loss) $ 33,987 $ 35,094 $ 22,621 $ (8,249)$ 83,453
----------------------------------------------------------------------------
----------------------------------------------------------------------------

Midstream
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
(continuing operations)
Light/medium oil (bpd) 7,302 6,623 6,640 6,569 6,815
Heavy oil (bpd) 2,506 2,011 2,004 1,838 2,057
Natural gas liquids (bpd) 1,505 1,457 1,310 1,331 1,401
Natural gas (mcfd) 75,840 77,803 78,560 97,489 82,469
Oil equivalent (boed) 23,953 23,058 23,047 25,986 24,018
----------------------------------------------------------------------------

Average selling price net
of transportation expense
(continuing operations)
(Cdn$)
Crude oil per bbl $ 43.75 $ 65.92 $ 54.94 $ 46.23 $ 52.45
(before realized
financial derivative
instruments)
Crude oil per bbl $ 42.77 $ 64.64 $ 54.09 $ 45.38 $ 51.47
(including realized
financial derivative
instruments)
Natural gas liquids
per barrel $ 53.89 $ 54.12 $ 51.91 $ 47.46 $ 51.91
Natural gas per mcf $ 7.98 $ 6.10 $ 5.90 $ 6.73 $ 6.66
(before realized
financial derivative
instruments)
Natural gas per mcf $ 7.82 $ 6.41 $ 6.26 $ 7.15 $ 6.92
(including realized
financial derivative
instruments)
----------------------------------------------------------------------------

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


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

As at As at
June 30, December 31,
2008 2007
------------------------------

Assets
Current assets
Cash and cash equivalents $ 1,621 $ -
Accounts receivable 384,623 338,105
Petroleum product inventory 111,776 84,638
Prepaid expenses and other current assets 12,177 8,313
Financial derivative instruments (note 8) 3,426 1,329
Assets held for sale - USOGP (note 10) 25,618 93,578
----------------------------------------------------------------------------
539,241 525,963

Investments 7,082 5,862
Property, plant and equipment 2,498,949 2,510,271
Intangible assets 165,064 171,793
Goodwill 517,299 517,299
Assets held for sale - USOGP (note 10) 282,064 2,027,604
----------------------------------------------------------------------------
$ 4,009,699 $ 5,758,792
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Liabilities
Current liabilities
Accounts payable and accrued liabilities $ 380,336 $ 347,224
Income taxes payable (note 10) 149,922 -
Cash distributions payable 25,870 25,100
Current portion of convertible
debentures (note 4) 19,564 19,198
Financial derivative instruments (note 8) 271,994 130,276
Liabilities held for sale - USOGP (note 10) 16,555 114,681
----------------------------------------------------------------------------
864,241 636,479

Long-term debt - revolving term credit
facilities (note 4) 626,192 923,996
Long-term debt - convertible debentures
(note 4) 258,705 256,440
Asset retirement obligation (note 5) 44,445 43,886
Long-term financial derivative
instruments (note 8) 475,378 146,199
Other long-term liabilities (note 7) 4,910 12,400
Future income taxes 204,198 302,089
Liabilities held for sale - USOGP (note 10) 73,184 628,502
Non-controlling interests (note 10)
Discontinued operations (USOGP) 14,691 1,100,136

Unitholders' equity
Unitholders' contributions (note 6) 2,780,366 2,750,374
Convertible debentures equity component 18,211 18,213
Contributed surplus (note 7) 714 801
Accumulated other comprehensive loss (30,757) (69,188)
Accumulated income 118,177 268,642
Accumulated cash distributions (1,442,956) (1,260,177)
----------------------------------------------------------------------------
1,443,755 1,708,665
----------------------------------------------------------------------------
$ 4,009,699 $ 5,758,792
----------------------------------------------------------------------------
----------------------------------------------------------------------------

The accompanying notes are an integral part of these statements.


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


Three months ended Six months ended
June 30, June 30,
--------------------------------------------
--------------------------------------------
2008 2007 2008 2007
--------------------------------------------
(restated - note 3) (restated - note 3)
Revenue
Revenue $ 887,328 $ 499,481 $ 1,682,753 $1,040,355
Realized loss on financial
derivative instruments (60,571) (11,740) (91,508) (14,674)
Unrealized loss on financial
derivative instruments (406,537) (23,746) (468,810) (2,879)
----------------------------------------------------------------------------
420,220 463,995 1,122,435 1,022,802

Expenses
Cost of goods sold 586,469 345,828 1,130,546 730,917
Production, operating and
maintenance 39,479 29,101 73,205 58,784
Transportation 8,016 4,375 16,543 11,024
Depletion, depreciation and
accretion 84,547 69,425 166,163 135,881
General and administrative
(note 7) 19,852 21,240 40,114 37,536
Interest on bank debt 11,170 8,200 24,165 17,544
Interest and accretion on
convertible debentures 3,663 3,746 7,323 7,517
Foreign exchange (gain)
loss and other (126) 433 (1,397) 641
----------------------------------------------------------------------------
----------------------------------------------------------------------------
753,070 482,348 1,456,662 999,844
----------------------------------------------------------------------------
----------------------------------------------------------------------------

(Loss) income from continuing
operations before taxes (332,850) (18,353) (334,227) 22,958
----------------------------------------------------------------------------
----------------------------------------------------------------------------

Capital tax expense 1,210 630 1,692 888
Current and withholding tax
(recovery) expense (1,211) (1,660) 3,824 2,898
Future income tax (recovery)
expense (71,554) 74,439 (103,555) 63,606
----------------------------------------------------------------------------
(71,555) 73,409 (98,039) 67,392
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Net loss for the period from
continuing operations (261,295) (91,762) (236,188) (44,434)
Net income from discontinued
operations (note 10) 77,214 45,563 85,723 41,328
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Net loss for the period (184,081) (46,199) (150,465) (3,106)
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Accumulated income, beginning
of period $ 302,258 $ 281,301 $ 268,642 $ 238,208
----------------------------------------------------------------------------
Accumulated income, end of
period $ 118,177 $ 235,102 $ 118,177 $ 235,102
----------------------------------------------------------------------------
Net loss from continuing
operations per unit - basic
and diluted $ (1.03) $ (0.42) $ (0.93)$ (0.21)
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Net loss per unit - basic and
diluted $ (0.72) $ (0.21) $ (0.59)$ (0.01)
----------------------------------------------------------------------------
----------------------------------------------------------------------------

The accompanying notes are an integral part of these statements.


PROVIDENT ENERGY TRUST
CONSOLIDATED STATEMENT OF CASH FLOWS
Canadian dollars (000s)
(unaudited)

Three months ended Six months ended
June 30, June 30,
--------------------------------------------
--------------------------------------------
2008 2007 2008 2007
--------------------------------------------
(restated - note 3) (restated - note 3)

Cash provided by operating
activities
Net loss for the period from
continuing operations $ (261,295) $ (91,762) $ (236,188) $ (44,434)
Add (deduct) non-cash items:
Depletion, depreciation and
accretion 84,547 69,425 166,163 135,881
Non-cash interest expense
and other 1,107 708 1,991 1,440
Non-cash unit based
compensation (note 7) 4,691 4,610 1,518 7,105
Unrealized loss on financial
derivative instruments 406,537 23,746 468,810 2,879
Unrealized foreign exchange
loss (gain) and other 1,437 435 (2,875) 938
Future income tax (recovery)
expense (71,554) 74,439 (103,555) 63,606
----------------------------------------------------------------------------
Funds flow from continuing
operations 165,470 81,601 295,864 167,415
Funds flow from discontinued
operations 76,017 16,902 125,853 18,128
----------------------------------------------------------------------------
Funds flow from operations 241,487 98,503 421,717 185,543
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Site restoration expenditures (1,101) (524) (2,638) (1,750)
Change in non-cash operating
working capital from
continuing operations (117,856) (15,146) (45,122) 43,893
Change in non-cash operating
working capital from
discontinued operations (76,057) 3,066 (26,631) 8,784
----------------------------------------------------------------------------
----------------------------------------------------------------------------
46,473 85,899 347,326 236,470
----------------------------------------------------------------------------

Cash (used for) provided by
financing activities
(Decrease) increase in
long-term debt (264,011) 156,735 (298,576) 99,233
Declared distributions to
unitholders (91,662) (80,236) (182,779) (156,507)
Issue of trust units, net
of issue costs 15,681 365,634 29,878 381,227
Change in non-cash financing
working capital 56 4,349 770 4,853
Financing activities from
discontinued operations 20,525 214,608 (42,630) 262,171
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(319,411) 661,090 (493,337) 590,977
----------------------------------------------------------------------------

Cash provided by (used for)
investing activities
Capital expenditures (34,210) (27,360) (118,792) (66,113)
Capitol Energy acquisition - (467,850) - (467,850)
Oil and gas property
acquisitions, net (10,432) (1,028) (19,451) (9,709)
Increase in investments - - (1,007) -
Proceeds on sale of assets,
net of tax (note 10) 206,349 - 206,349 7,624
Change in non-cash investing
working capital 133,319 (6,468) 137,125 (5,345)
Investing activities from
discontinued operations (33,826) (237,727) (62,553) (287,337)
----------------------------------------------------------------------------
----------------------------------------------------------------------------
261,200 (740,433) 141,671 (828,730)
----------------------------------------------------------------------------

(Decrease) increase in cash
and cash equivalents (11,738) 6,556 (4,340) (1,283)
Cash and cash equivalents,
beginning of period 14,218 2,463 6,820 10,302
----------------------------------------------------------------------------
Cash and cash equivalents,
end of period 2,480 $ 9,019 $ 2,480 $ 9,019
Cash and cash equivalents,
end of period from
discontinued operations 859 $ 3,149 $ 859 $ 3,149
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Cash and cash equivalents,
end of period from
continuing operations 1,621 $ 5,870 $ 1,621 $ 5,870
----------------------------------------------------------------------------
----------------------------------------------------------------------------

Supplemental disclosure of
cash flow information
Cash interest paid including
debenture interest 19,688 $ 15,451 $ 41,767 $ 28,856
Cash taxes paid 8,772 $ 1,012 $ 10,872 $ 8,799
----------------------------------------------------------------------------
----------------------------------------------------------------------------

The accompanying notes are an integral part of these statements.


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

Three months ended Six months ended
June 30, June 30,
--------------------------------------------
--------------------------------------------
2008 2007 2008 2007
--------------------------------------------
(restated - note 3) (restated - note 3)

Net loss $ (184,081) $ (46,199) $ (150,465) $ (3,106)
----------------------------------------------------------------------------

Other comprehensive income
(loss), net of taxes
Foreign currency translation
adjustments (4,593) (11,485) 7,943 (15,124)
Reclassification adjustment
for foreign currency losses
included in net income 30,302 - 30,302 -
Unrealized gain (loss) on
available-for-sale
investments (net of taxes) 252 (492) 186 (1,281)
----------------------------------------------------------------------------
25,961 (11,977) 38,431 (16,405)
----------------------------------------------------------------------------

Comprehensive loss $ (158,120) $ (58,176) $ (112,034) $ (19,511)
----------------------------------------------------------------------------
Accumulated other
comprehensive loss,
beginning of period (56,718) (46,722) (69,188) (42,294)
Other comprehensive income
(loss) 25,961 (11,977) 38,431 (16,405)
----------------------------------------------------------------------------
Accumulated other
comprehensive loss, end
of period $ (30,757) $ (58,699) $ (30,757) $ (58,699)
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Accumulated income, end of
period 118,177 235,102 118,177 235,102
Accumulated cash disributions,
end of period (1,442,956) (1,083,332) (1,442,956)(1,083,332)
----------------------------------------------------------------------------
Retained earnings (deficit),
end of period (1,324,779) (848,230) (1,324,779) (848,230)
----------------------------------------------------------------------------
Total retained earnings
(deficit) and accumulated
other comprehensive loss,
end of period $ (1,355,536) $ (906,929)$(1,355,536) $(906,929)
----------------------------------------------------------------------------
----------------------------------------------------------------------------

The accompanying notes 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)
(unaudited)

June 30, 2008


The Interim Consolidated Financial Statements of Provident Energy Trust ("the Trust") have been prepared by management in accordance with accounting principles generally accepted in Canada. Certain information and disclosures normally required in the notes to the annual financial statements have been condensed or omitted. The Interim Consolidated Financial Statements should be read in conjunction with the Trust's audited Financial Statements and notes for the year ended December 31, 2007.

1. Significant accounting policies

The Interim Consolidated Financial Statements have been prepared based on the consistent application of the accounting policies and procedures as set out in the Consolidated Financial Statements of the Trust for the year ended December 31, 2007 and are consistent with policies adopted in the second quarter of 2007, except as described in note 2. Certain comparative numbers have been reclassified to conform with the current period's presentation. In particular, the comparative figures have been reclassified to reflect discontinued operations presentation for the United States oil and natural gas production (USOGP) business (see note 10).

2. Changes in accounting policies and practices

(i) Inventory

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

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

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

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

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

(ii) Capital disclosures

In the first quarter of 2008, the Trust adopted CICA Handbook Section 1535 "Capital Disclosures" which addresses the requirements for an entity to disclose qualitative information about its objectives, policies and processes for managing capital. This section also establishes the requirement for an entity to disclose quantitative data about what it regards as capital as well as disclose whether it has complied with any externally imposed capital requirements and, if not, the consequences of such non-compliance. The new disclosure is included in note 9.

(iii) Financial instruments - disclosures

In the first quarter of 2008, the Trust adopted CICA Handbook Section 3862 "Financial Instruments-Disclosures" and Section 3863 "Financial Instruments-Presentation". Section 3862 requires entities to provide disclosures in their financial statements that enable users to evaluate the significance of financial instruments to the entity's financial position and performance. It also requires that entities disclose the nature and extent of risks arising from financial instruments and how the entity manages those risks. Section 3863 establishes presentation guidelines for financial instruments and non-financial derivatives and addresses the classification of financial instruments, from the perspective of the issuer, between liabilities and equity, the classification of related interest, dividends, losses and gains, and circumstances in which financial assets and financial liabilities are offset. The new disclosure is included in note 8.

3. Restatement of 2007 interim consolidated financial statements

As previously disclosed in the third quarter of 2007, the Trust determined that an adjustment was necessary principally due to commercial transactions within the Midstream segment that resulted in overstated inventory balances. Internal accounting controls had identified the issue. Related cash settlements with third parties were not affected.

The effect of the restatement on the interim consolidated financial statements for the second quarter and six months ended June 30, 2007 is summarized below. There was no effect on 2006 or prior periods.



Effect on the Effect on the
three months six months
ended June 30, ended June 30,
(000's except per unit amounts) 2007 2007
----------------------------------------------------------------------------

Increase in accounts receivable $ 888 $ 4,026
(Decrease) in petroleum product inventory (8,095) (21,321)
Decrease in future income tax liability 2,054 4,929
----------------------------------------------------------------------------
(Decrease) in unitholders' equity $ (5,153) $ (12,366)
----------------------------------------------------------------------------
----------------------------------------------------------------------------

(Increase) in cost of goods sold $ (7,207) $ (17,295)
Decrease in future income tax expense 2,054 4,929
----------------------------------------------------------------------------
(Decrease) in net income $ (5,153) $ (12,366)
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(Decrease) in net income per unit - basic and
diluted $ (0.02) $ (0.05)
----------------------------------------------------------------------------
----------------------------------------------------------------------------


4. Long-term debt

December 31,
June 30, 2008 2007
----------------------------------------------------------------------------
Revolving term credit facilities $ 626,192 $ 923,996
----------------------------------------------------------------------------
Convertible debentures 278,269 275,638
Current portion of convertible debentures (19,564) (19,198)
----------------------------------------------------------------------------
258,705 256,440
----------------------------------------------------------------------------
Total $ 884,897 $ 1,180,436
----------------------------------------------------------------------------
----------------------------------------------------------------------------


(i) Revolving term credit facility

At June 30, 2008 the Trust had a $1,125 million term credit facility (December 31, 2007 - $1,125 million). At June 30, 2008, $626.7 million was drawn on the facility. Included in the carrying value at June 30, 2008 were financing costs of $0.5 million.

At June 30, 2008 the Trust had letters of credit guaranteeing Provident's performance under certain commercial and other contracts that totaled $29.5 million. The guarantees totaled $31.6 million at December 31, 2007.

In the second quarter of 2008, under the terms of the credit facility, the expiry date of the facility was extended from May 30, 2010 to May 30, 2011.

As at June 30, 2008 the Trust was not in compliance with a covenant under the credit facility agreement. The non-compliance was subsequently waived by the Trust's lenders.

(ii) Convertible debentures

The Trust may elect to satisfy interest and principal obligations by the issue of trust units. For the six month ended June 30, 2008, $25 thousand of the face value of debentures were converted to trust units at the election of debenture holders (2007 - $0.6 million). Included in the carrying value at June 30, 2008 were financing costs of $5.8 million. The fair value of the convertible debentures at June 30, 2008 approximates the face value of the instruments. The following table details each convertible debenture:



Convertible As at As at
Debentures June 30, 2008 December 31, 2007
----------------------------------------------------------------------------
($000s Conversion
except Carrying Carrying Price
conversion Value Face Value Face per
pricing) (1) Value (1) Value Maturity Date unit (2)
----------------------------------------------------------------------------
6.5%
Convertible
Debentures $141,863 $149,980 $140,515 $149,980 April 30, 2011 14.75
6.5%
Convertible
Debentures 92,174 98,999 91,460 99,024 Aug. 31, 2012 13.75
8.0%
Convertible
Debentures 24,668 25,109 24,465 25,109 July 31, 2009 12.00
8.75%
Convertible
Debentures 19,564 19,931 19,198 19,931 Dec. 31, 2008 11.05
----------------------------------------------------------------------------
$278,269 $294,019 $275,638 $294,044
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(1) Excluding equity component of convertible debentures
(2) The debentures may be converted into trust units at the option of the
holder of the debenture at the conversion price per unit


5. 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.



Three month ended Six months ended
June 30, June 30,
----------------------------------------------------------------------------
($000s) 2008 2007 2008 2007
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Carrying amount, beginning of
period $ 44,112 $ 33,394 $ 43,886 $ 33,246
Acquisitions - 1,752 - 1,752
Increase in liabilities incurred
during the period 336 204 1,022 763
Settlement of liabilities during
the period (1,101) (524) (2,638) (1,750)
Decrease in liabilities due to
disposition - (449) - (449)
Accretion of liability 1,098 841 2,175 1,656
----------------------------------------------------------------------------
Carrying amount, end of period $ 44,445 $ 35,218 $ 44,445 $ 35,218
----------------------------------------------------------------------------
----------------------------------------------------------------------------


6. Unitholders' contributions

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



Six months ended June 30,
----------------------------------------------------------------------------
2008 2007
----------------------------------------------------------------------------
Number of Amount Number of Amount
Trust Units units (000s) units (000s)
----------------------------------------------------------------------------
Balance at beginning of
period 252,634,773 $ 2,750,374 211,228,407 $ 2,254,048
Issued pursuant to unit
option plan 142,940 1,292 628,437 6,520
Issued pursuant to the
distribution reinvestment
plan 2,326,646 23,828 1,504,676 17,712
To be issued pursuant to
the distribution
reinvestment plan 419,776 4,846 224,779 2,868
Debenture conversions 1,818 26 56,699 646
----------------------------------------------------------------------------
Balance at end of period 255,525,953 $ 2,780,366 213,642,998 $ 2,281,794
----------------------------------------------------------------------------
----------------------------------------------------------------------------


The per trust unit amounts for the quarter ended June 30, 2008 were calculated based on the weighted average number of units outstanding of 254,404,362 (2007 - 216,844,738). The diluted per trust unit amounts for 2008 are calculated including an additional 64,075 trust units (2007 - 240,252) for the dilutive effect of the unit option plan and convertible debentures.

The per trust unit amounts for the six months ended June 30, 2008 were calculated based on the weighted average number of units outstanding of 253,659,326 (2007 - 214,300,704). The diluted per trust unit amounts for 2008 are calculated including an additional 64,075 trust units (2007 - 240,252) for the dilutive effect of the unit option plan and convertible debentures.

7. Unit based compensation

(i) Restricted/Performance units

As of June 30, 2008 there were 1,074,187 RTUs and 3,190,132 PTUs outstanding (December 31, 2007 - 849,672 RTUs and 2,478,037 PTUs). The fair value estimate associated with the RTUs and PTUs is expensed in the statement of operations over the vesting period. At June 30, 2008, $18.9 million (December 31, 2007 - $9.9 million) is included in accounts payable and accrued liabilities for this plan and $4.9 million (December 31, 2007 - $12.4 million) is included in other long-term liabilities. The following table reconciles the expense recorded for RTUs and PTUs.



Three months ended Six months ended
June 30, June 30,
----------------------------------------------------------------------------
2008 2007 2008 2007
----------------------------------------------------------------------------
Cash general and administrative $ - $ - $ 8,287 $ 1,767
Non-cash unit based compensation
(included in general and
administrative) 4,691 4,592 1,518 7,050
Production, operating and
maintenance expense 192 52 423 227
----------------------------------------------------------------------------
$ 4,883 $ 4,644 $ 10,228 $ 9,044
----------------------------------------------------------------------------
----------------------------------------------------------------------------


(ii) Unit option plan

At June 30, 2008, the Trust had 1,105,230 options outstanding and exercisable (December 31, 2007 - 1,279,169) with strike prices ranging from $10.49 to $12.14 per unit (December 31, 2007 - $10.49 and $12.14 per unit). The weighted average remaining contractual life of the options was 0.4 years (December 31, 2007 - 0.87 years) and the weighted average exercise price was $11.04 per unit (December 31, 2007 - $11.04 per unit) excluding average potential reductions to the strike prices of $2.02 per unit (December 31, 2007 - $1.77 per unit).

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



Three months ended Six months ended
June 30, June 30,
----------------------------------------------------------------------------
2008 2007 2008 2007
----------------------------------------------------------------------------
Contributed surplus, beginning of
the period $ 801 $ 1,015 $ 801 $ 1,315
Non-cash unit based compensation
(included in general and
administrative) - 18 - 55
Benefit on options exercised
charged to unitholders' equity (87) (98) (87) (435)
----------------------------------------------------------------------------
Contributed surplus, end of period $ 714 $ 935 $ 714 $ 935
----------------------------------------------------------------------------
----------------------------------------------------------------------------


8. Financial instruments

Risk Management overview

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

Provident's Risk Management group executes the program with oversight from the Risk Management Committee ("RMC"), which provides regular reports to the Audit Committee and Board of Directors.

Provident has established and implemented Risk Management strategies, policies and limits that are monitored by Provident's Risk Management group. The derivative instruments the Trust uses include put and call options, costless collars, participating swaps, and fixed price products that settle against indexed referenced pricing. Put option contracts effectively create a floor price for the commodity while allowing for full participation if prices increase. Call options are contracts that allow for a commodity to be sold at a fixed price at the option of the contract holder. Costless collars are contracts entered into that provide a floor and a ceiling price to limit the risk if prices fall and allowing upward participation within a set range. Participating swaps are contracts entered into that provide a floor and also provide a ceiling for a certain percentage of the volume of the contract. This type of derivative allows for price protection if the price falls, while still allowing some participation if the price increases. Fixed price swaps are contracts that specify a fixed price at which a certain volume of product will be bought or sold at in the future.

The Risk Management group monitors risk exposure by generating and reviewing mark-to-market reports and counterparty credit exposure of Provident's outstanding derivative contracts. Additional monitoring activities include reviewing available derivative positions, regulatory changes and bank and analyst reports.

Provident's commodity price risk management program includes a consistent, active and disciplined program that utilizes derivative instruments to provide for insurance against lower commodity prices and product margins, as well as fluctuating interest and foreign exchange rates. The program is designed to stabilize cash flows in order to support cash distributions, capital programs and bank financing. The risk management strategy protects a percentage of Provident's oil and natural gas production against a decline in commodity prices. Provident seeks to use products that allow participation in a rising commodity price environment where possible and economic. The program provides price stabilization and protection of a percentage of inventory values and fractionation spread margin associated with the midstream business unit. As well, the Provident risk management strategy reduces foreign exchange risk due to the exposure arising from the conversion of U.S. dollars into Canadian dollars.

Fair Values

The fair values of financial instruments are determined by reference to independent monthly forward settlement prices, interest rate yield curves, currency rates, and volatility rates at the period-end dates. All of Provident's financial instruments are executed in liquid markets.



Held Total
As at June for Held to Available Loans and Other Carrying
30, 2008 Trading Maturity for Sale Receivables Liabilities Value
----------------------------------------------------------------------------

Assets
Cash and
cash
equivalents $ 1,621 $ - $ - $ - $ - $ 1,621
Accounts
receivable - - - 384,623 - 384,623
Financial
derivative
instruments
- current
asset 3,426 - - - - 3,426
Investments - 4,622 2,460 - - 7,082
----------------------------------------------------------------------------
$ 5,047 $ 4,622 $ 2,460 $ 384,623 $ - $ 396,752
----------------------------------------------------------------------------
----------------------------------------------------------------------------

Liabilities
Accounts
payable and
accrued
liabilities $ - $ - $ - $ - $ 380,336 $ 380,336
Cash
distributions
payable - - - - 25,870 25,870
Current
portion of
convertible
debentures - - - - 19,564 19,564
Financial
derivative
instruments
- current
liabilities 271,994 - - - - 271,994
Long-term
debt -
revolving
term credit
facilities - - - - 626,192 626,192
Long-term
debt -
convertible
debentures - - - - 258,705 258,705
Financial
derivative
instruments
- long
-term
liabilities 475,378 - - - - 475,378
Other
long-term
liabilities - - - - 4,910 4,910
----------------------------------------------------------------------------
$747,372 $ - $ - $ - $1,315,577 $2,062,949
----------------------------------------------------------------------------
----------------------------------------------------------------------------


Except as disclosed in note 4 in connection with the convertible debentures, there were no significant differences between the carrying value of these financial instruments and their estimated fair value as at June 30, 2008.

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



As at As at
June 30, December 31,
----------------------------------------------------------------------------
($000s) 2008 2007
----------------------------------------------------------------------------
Commodity prices
Crude Oil $ 41,300 $ 19,215
Natural Gas 9,950 (5,901)
Midstream 692,736 261,587
Other (40) 245
----------------------------------------------------------------------------
Total $ 743,946 $ 275,146
----------------------------------------------------------------------------
----------------------------------------------------------------------------


Market Risk

Market risk is the risk that the fair value of a financial instrument will fluctuate because of changes in market prices. Market risk generally comprises of price risk, currency risk and interest rate risk.

a) Price risk

Commodity Price Risk Management Program

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

Oil and Natural Gas

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

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

Midstream

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

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

b) Currency risk

Provident's oil, natural gas and NGL sales are exposed to both positive and negative effects of fluctuations in the Canadian/U.S. exchange rate. Provident manages this exposure by matching a significant portion of the cash costs that it expects with revenues in the same currency. As well, Provident uses derivative instruments to manage the U.S. cash requirements of its U.S. and Canadian business lines.

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

c) Interest rate risk

The Trust's revolving term credit facilities bear interest at a floating rate. Using debt levels as at June 30, 2008, an increase/decrease of 50 basis points in the lender's base rate would result in an increase/decrease of annual interest expense of approximately $3.1 million.

Financial derivative sensitivity analysis

The following table shows the impact on unrealized (loss) gain on financial derivative instruments if the underlying risk variables of the financial derivative instruments changed by a specified amount, with other variables held constant.



(000's) + Change - Change
----------------------------------------------------------------------------
COGP
Crude Oil (WTI +/- $10.00 per bbl) $ (5,448) $ 5,328
Natural Gas (AECO +/- $1.00 per gj) (3,020) 2,555
----------------------------------------------------------------------------
----------------------------------------------------------------------------

Midstream
Crude Oil (WTI +/- $10.00 per bbl) (143,902) 141,755
Natural Gas (AECO +/- $1.00 per gj) 78,128 (77,316)
NGL's (Belvieu +/- $0.15 per gal) 3,218 (3,678)
Foreign Exchange
($U.S. vs $Cdn) (FX rate +/- $ 0.01) (2,215) 2,923
----------------------------------------------------------------------------
----------------------------------------------------------------------------


Liquidity Risk

Liquidity risk is the risk the Trust will not be able to meet its financial obligations as they fall due. The Trust's approach to managing liquidity risk is to ensure that it always has sufficient cash and credit facilities to meet its obligations when due, without incurring unacceptable losses or damage to the Trust's reputation.

Management typically forecasts cash flows for a period of twelve months to identify financing requirements. These requirements are then addressed through a combination of committed and demand credit facilities and access to capital markets, as discussed in note 9.

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



As at June 30, 2008 Payment due by period
----------------------------------------------------------------------------
Less
than 1 1 to 3 4 to 5
($000s) Total year years years
----------------------------------------------------------------------------
Accounts payable and accrued
liabilities $ 380,336 $ 380,336 $ - $ -
Cash distributions payable 25,870 25,870 - -
Current portion of
convertible debentures 19,564 19,564 - -
Financial derivative
instruments - current 271,994 271,994 - -
Long-term debt - revolving
term credit facilities (1) 626,192 - 626,192 -
Long-term debt - convertible
debentures 258,705 - 166,531 92,174
Long-term financial
derivative instruments 475,378 - 339,264 136,114
Other long-term liabilities 4,910 - 4,910 -
----------------------------------------------------------------------------
Total $ 2,062,949 $ 697,764 $ 1,136,897 $ 228,288
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(1) The terms of the Canadian credit facility have a revolving three year
period expiring on May 30, 2011.


Credit Risk

Provident's Credit Policy governs the activities undertaken to mitigate the risks associated with counterparty (customer) non-payment. The Policy requires a formal credit review for counterparties entering into a commodity contract with Provident. This review determines an approved credit limit. Activities undertaken include regular monitoring of counterparty exposures, an annual review of all active counterparties, utilizing master netting arrangements and obtaining financial assurances where warranted. Financial assurances include guarantees, letters of credit and cash. In addition, the policy sets criteria to ensure that Provident has a diversified base of creditors.

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

9. Capital management

Provident considers its total capital to be comprised of net debt and Unitholders' Equity. Net debt is comprised of long-term debt and working capital deficit (surplus), excluding balances for the current portion of financial derivative instruments. The balance of these items at June 30, 2008 and December 31, 2007 was as follows:



As at As at
June 30, December 31,
----------------------------------------------------------------------------
($000s) 2008 2007
----------------------------------------------------------------------------
Working capital deficit (surplus) (1) $ 45,931 $ (58,732)
Long-term debt (including current portion) 904,461 1,199,634
----------------------------------------------------------------------------
Net debt 950,392 1,140,902
Unitholders' equity 1,443,755 1,708,665
----------------------------------------------------------------------------
Total capitalization $ 2,394,147 $ 2,849,567
----------------------------------------------------------------------------
----------------------------------------------------------------------------

Net debt to total capitalization (%) 40% 40%
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(1) The working capital deficit (surplus) excludes balances for the current
portion of financial derivative instruments.


Provident's primary objective for managing capital is to maximize long-term Unitholder value by:

- providing an appropriate return to shareholders relative to the risk of Provident's underlying assets; and

- ensuring financing capacity for Provident's internal development opportunities and acquisitions of energy related assets that are expected to add value to our Unitholders.

Provident makes adjustments to its capital structure based on economic conditions and the Company's planned requirements. Provident has the ability to adjust its capital structure by issuing new equity or debt, controlling the amount it returns to unitholders, and making adjustments to its capital expenditure program. Provident relies on cash flow from operations, external lines of credit and access to equity markets to fund capital programs and acquisitions.

The Trust is subject to certain capital growth restrictions as a result of the Canadian trust tax legislation passed in June 2007 and effective January 1, 2011. The restrictions provide that "normal growth" would include equity growth within certain "safe harbour" limits, measured by reference to the Trust's market capitalization as of the end of trading on October 31, 2006. These rules limit the amount of Unitholders' capital that can be issued by the Trust in each of the next three years, as follows:



----------------------------------------------------------------------------
($ billions) Annual Cumulative
----------------------------------------------------------------------------
Normal growth capital allowed in:
2008 (1) 0.6 1.7
2009 0.6 2.3
2010 0.5 2.8
----------------------------------------------------------------------------
(1) The Trust's allowed growth capital prior to 2008 was approximately $1.1
billion.


If the maximum equity growth allowed is exceeded, the Trust may be subject to trust taxation prior to 2011. In 2007, the Trust issued equity amounting to $496.3 million.

10. Discontinued operations (USOGP)

In February, 2008 the Trust announced a strategic process respecting the decision to dispose of the operations that comprise the United States oil and natural gas production (USOGP) business. Effective in the first quarter of 2008, Provident's USOGP business is accounted for as discontinued operations and comparative figures have been reclassified to conform with this presentation.

In June, 2008 the Trust sold a portion of the USOGP business, consisting of its 22 percent interest in BreitBurn Energy Partners, L.P. (MLP) and its 96 percent interest in BreitBurn GP LLC, for cash proceeds, net of transaction costs, of U.S. $342.2 million. The Trust has recorded a gain on sale of $187.9 million and $141.8 million in current tax expense, related to this transaction. Also recorded was a realized foreign exchange loss of $30.3 million, representing the recognition of the related portion of the foreign exchange loss in accumulated other comprehensive income, which was generated since acquisition in 2006. These amounts are recorded as part of net income from discontinued operations for the three and six months ended June 30, 2008. Included in income taxes payable at June 30, 2008 was $141.8 million related to this transaction.

In July, 2008 the Trust announced an agreement to sell the remaining portion of the USOGP business, comprised of an approximate 96 per cent interest in BreitBurn Energy Company L.P., for total consideration of U.S. $305 million, consisting of cash proceeds of U.S. $295 million and a U.S. $10 million note. The transaction is expected to close prior to the end of August with proceeds initially applied to Provident's Canadian credit facility.

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



As at As at
Balance sheets June 30, December 31,
Canadian dollars (000s) 2008 2007
----------------------------------------------------------------------------
Assets
Current assets $ 25,618 $ 93,578
----------------------------------------------------------------------------
Property, plant and equipment 280,588 2,008,549
Other long-term assets 1,476 19,055
----------------------------------------------------------------------------
282,064 2,027,604
----------------------------------------------------------------------------
$ 307,682 $ 2,121,182
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Liabilities
Current liabilities
Accounts payable and accrued liabilities $ 9,734 $ 77,244
Financial derivative instruments 6,821 37,437
----------------------------------------------------------------------------
16,555 114,681
----------------------------------------------------------------------------
Long-term debt - revolving term credit facilities 18,141 368,836
Long-term financial derivative instruments 2,441 66,382
Asset retirement obligation and other long-term
liabilities 11,169 45,373
Future income taxes 41,433 147,911
----------------------------------------------------------------------------
73,184 628,502
----------------------------------------------------------------------------
Non-controlling interests 14,691 1,100,136
----------------------------------------------------------------------------
Net Assets - discontinued operations $ 203,252 $ 277,863
----------------------------------------------------------------------------
----------------------------------------------------------------------------


Net income from Three months Six months
discontinued operations ended June 30, ended June 30,
----------------------------------------------------------------------------
Canadian dollars (000's) 2008 2007 2008 2007
----------------------------------------------------------------------------
Revenue $ 146,888 $ 48,724 $ 284,294 $ 86,404
----------------------------------------------------------------------------
(Loss) income from
discontinued operations before
taxes, non-controlling
interests and impact of sale
of discontinued operations (242,126) 91,525 (256,572) 79,686
Gain on sale of discontinued
operations 187,920 - 187,920 -
Foreign exchange loss related
to sale of discontinued
operations (30,302) - (30,302) -
Current and withholding tax
(expense) recovery (128,551) 587 (128,565) (232)
Future income tax recovery
(expense) 99,266 (48,703) 109,086 (43,776)
Non-controlling interests 191,007 2,154 204,156 5,650
----------------------------------------------------------------------------
Net income from discontinued
operations for the period $ 77,214 $ 45,563 $ 85,723 $ 41,328
----------------------------------------------------------------------------
----------------------------------------------------------------------------


11. Segmented information

The Trust's business activities are conducted through two business segments: Canadian oil and natural gas production and Midstream.

Oil and natural gas production includes exploitation, development and production of crude oil and natural gas reserves. Midstream includes fractionation, transportation, loading and storage of natural gas liquids, and marketing of crude oil and natural gas liquids.

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



Three months ended June 30, 2008
------------------------------------------------
Canadian Oil
and Natural
Gas Production Midstream (1) Total
----------------------------------------------------------------------------

Revenue
Gross production revenue $ 212,382 $ - $ 212,382
Royalties (38,686) - (38,686)
Product sales and service
revenue - 713,632 713,632
Realized loss on financial
derivative instruments (9,254) (51,317) (60,571)
----------------------------------------------------------------------------
164,442 662,315 826,757
----------------------------------------------------------------------------

Expenses
Cost of goods sold - 586,469 586,469
Production, operating and
maintenance 35,558 3,921 39,479
Transportation 4,520 3,496 8,016
Foreign exchange (gain) loss
and other (596) (967) (1,563)
General and administrative 7,828 7,627 15,455
----------------------------------------------------------------------------
47,310 600,546 647,856
----------------------------------------------------------------------------

Earnings before interest,
taxes, depletion,
depreciation, accretion and
other non-cash items 117,132 61,769 178,901
Other revenue
Unrealized (loss) gain on
financial derivative
instruments (23,421) (383,116) (406,537)
----------------------------------------------------------------------------

Other expenses
Depletion, depreciation and
accretion 75,423 9,124 84,547
Interest on bank debt 2,792 8,378 11,170
Interest and accretion on
convertible debentures 916 2,747 3,663
Unrealized foreign exchange
loss (gain) and other 44 1,393 1,437
Non-cash unit based
compensation 2,550 2,141 4,691
Internal management charge (294) - (294)
Capital tax expense 1,210 - 1,210
Current and withholding tax
(recovery) expense (86) (1,125) (1,211)
Future income tax (recovery)
expense (17,779) (53,775) (71,554)
----------------------------------------------------------------------------
64,776 (31,117) 33,659
----------------------------------------------------------------------------
Net (loss) income for the
period from continuing
operations $ 28,935 $ (290,230) $ (261,295)
Net income from discontinued
operations (note 10) 77,214
----------------------------------------------------------------------------
Net loss for the period $ (184,081)
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(1) Included in the Midstream segment is product sales and service revenue
of $43.7 million associated with U.S. operations.


As at and for the three months ended June 30, 2008
----------------------------------------------------
Canadian Oil
and Natural
Gas Production Midstream Total
----------------------------------------------------------------------------
Selected balance sheet items
Capital assets
Property, plant and equipment net $1,762,527 $ 736,422 $ 2,498,949
Intangible assets - 165,064 165,064
Goodwill 416,890 100,409 517,299
Capital expenditures
Capital Expenditures 28,491 5,719 34,210
Oil and gas property acquisitions,
net 10,432 - 10,432
Working capital
Accounts receivable 106,612 278,011 384,623
Petroleum product inventory - 111,776 111,776
Accounts payable and accrued
liabilities 144,294 236,042 380,336
Long-term debt - revolving term
credit facilities 156,548 469,644 626,192
Long-term debt - convertible
debentures 64,676 194,029 258,705
Financial derivative instruments $ 51,210 $ 692,736 $ 743,946
----------------------------------------------------------------------------
----------------------------------------------------------------------------


Three months ended June 30, 2007
---------------------------------------------
Canadian Oil
and Natural Midstream
Gas Production (1) (2) Total
----------------------------------------------------------------------------
Revenue
Gross production revenue $ 112,458 $ - $ 112,458
Royalties (21,087) - (21,087)
Product sales and service revenue - 408,110 408,110
Realized loss on financial
derivative instruments (1,343) (10,397) (11,740)
----------------------------------------------------------------------------
90,028 397,713 487,741
----------------------------------------------------------------------------

Expenses
Cost of goods sold - 345,828 345,828
Production, operating and
maintenance 25,104 3,997 29,101
Transportation 1,586 2,789 4,375
Foreign exchange (gain) loss and
other (2) - (2)
General and administrative 7,883 9,125 17,008
----------------------------------------------------------------------------
34,571 361,739 396,310
----------------------------------------------------------------------------

Earnings before interest, taxes,
depletion, depreciation,
accretion and other non-cash items 55,457 35,974 91,431
Other revenue
Unrealized (loss) gain on
financial derivative instruments 12,355 (36,101) (23,746)
----------------------------------------------------------------------------

Other expenses
Depletion, depreciation and
accretion 58,272 11,153 69,425
Interest on bank debt 2,050 6,150 8,200
Interest and accretion on
convertible debentures 936 2,810 3,746
Unrealized foreign exchange loss
(gain) and other (917) 1,352 435
Non-cash unit based compensation 2,025 2,585 4,610
Internal management charge (378) - (378)
Capital tax expense 630 - 630
Current and withholding tax
(recovery) expense 3 (1,663) (1,660)
Future income tax (recovery)
expense (3) (45,238) 119,677 74,439
----------------------------------------------------------------------------
17,383 142,064 159,447
----------------------------------------------------------------------------
Net (loss) income for the period
from continuing operations $ 50,429 $ (142,191) $ (91,762)
Net income from discontinued
operations (note 10) 45,563
----------------------------------------------------------------------------
Net loss for the period $ (46,199)
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(1) Included in the Midstream segment is product sales and service revenue
of $43.0 million associated with U.S. operations.
(2) Restated - see note 3.
(3) Future income tax (recovery) expense includes a charge of $104.7
million relating to the enactment of Bill C-52, Budget Implementation
Act 2007 by the Canadian government.


As at and for the three months ended June 30, 2007
----------------------------------------------------
Canadian Oil
and Natural
Gas Production Midstream (1) Total
----------------------------------------------------------------------------
Selected balance sheet items
Capital assets
Property, plant and
equipment net $ 1,693,767 $ 729,260 $ 2,423,027
Intangible assets - 182,464 182,464
Goodwill 417,614 100,409 518,023
Capital expenditures
Capital Expenditures 21,616 5,744 27,360
Corporate acquisitions 467,850 - 467,850
Oil and gas property
acquisitions, net 1,028 - 1,028
Goodwill additions 86,670 - 86,670
Working capital
Accounts receivable 76,197 185,345 261,542
Petroleum product
inventory - 88,675 88,675
Accounts payable and
accrued liabilities 97,129 193,996 291,125
Long-term debt -
revolving term
credit facilities 210,529 631,586 842,115
Long-term debt -
convertible
debentures 69,612 208,837 278,449
Financial derivative
instruments
(asset) liability $ (5,955) $ 68,983 $ 63,028
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(1) Restated - see note 3.


Six months ended June 30, 2008
----------------------------------------------
Canadian Oil
and Natural
Gas Production Midstream(1) Total
----------------------------------------------------------------------------

Revenue
Gross production revenue $ 366,768 $ - $ 366,768
Royalties (67,283) - (67,283)
Product sales and service revenue - 1,383,268 1,383,268
Realized loss on financial
derivative instruments (12,228) (79,280) (91,508)
----------------------------------------------------------------------------
287,257 1,303,988 1,591,245
----------------------------------------------------------------------------

Expenses
Cost of goods sold - 1,130,546 1,130,546
Production, operating and
maintenance 65,934 7,271 73,205
Transportation 8,164 8,379 16,543
Foreign exchange (gain) loss and
other 928 550 1,478
General and administrative 19,751 19,486 39,237
----------------------------------------------------------------------------
94,777 1,166,232 1,261,009
----------------------------------------------------------------------------

Earnings before interest, taxes,
depletion, depreciation,
accretion and other non-cash items 192,480 137,756 330,236
Other revenue
Unrealized (loss) gain on
financial derivative instruments (37,789) (431,021) (468,810)
----------------------------------------------------------------------------

Other expenses
Depletion, depreciation and
accretion 147,925 18,238 166,163
Interest on bank debt 6,041 18,124 24,165
Interest and accretion on
convertible debentures 1,831 5,492 7,323
Unrealized foreign exchange loss
(gain) and other 45 (2,920) (2,875)
Non-cash unit based compensation 805 713 1,518
Internal management charge (641) - (641)
Capital tax expense 1,692 - 1,692
Current and withholding tax
(recovery) expense (199) 4,023 3,824
Future income tax (recovery)
expense (41,334) (62,221) (103,555)
----------------------------------------------------------------------------
116,165 (18,551) 97,614
----------------------------------------------------------------------------
Net (loss) income for the period
from continuing operations $ 38,526 $ (274,714) $ (236,188)
Net income from discontinued
operations (note 10) 85,723
----------------------------------------------------------------------------
Net loss for the period $ (150,465)
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(1) Included in the Midstream segment is product sales and service revenue
of $164.3 million associated with U.S. operations.


As at and for the six months ended June 30, 2008
--------------------------------------------------
Canadian Oil
and Natural
Gas Production Midstream Total
----------------------------------------------------------------------------
Selected balance sheet items
Capital assets
Property, plant and
equipment net $ 1,762,527 $ 736,422 $ 2,498,949
Intangible assets - 165,064 165,064
Goodwill 416,890 100,409 517,299
Capital expenditures
Capital Expenditures 107,649 11,143 118,792
Oil and gas property
acquisitions, net 19,451 - 19,451
Working capital
Accounts receivable 106,612 278,011 384,623
Petroleum product inventory - 111,776 111,776
Accounts payable and
accrued liabilities 144,294 236,042 380,336
Long-term debt - revolving
term credit facilities 156,548 469,644 626,192
Long-term debt - convertible
debentures 64,676 194,029 258,705
Financial derivative
instruments $ 51,210 $ 692,736 $ 743,946
----------------------------------------------------------------------------
----------------------------------------------------------------------------


Six months ended June 30, 2007
------------------------------------------------
Canadian Oil
and Natural
Gas Production Midstream (1)(2) Total
----------------------------------------------------------------------------

Revenue
Gross production revenue $ 217,656 $ - $ 217,656
Royalties (40,772) - (40,772)
Product sales and service
revenue - 863,471 863,471
Realized loss on financial
derivative instruments (2,188) (12,486) (14,674)
----------------------------------------------------------------------------
174,696 850,985 1,025,681
----------------------------------------------------------------------------

Expenses
Cost of goods sold - 730,917 730,917
Production, operating and
maintenance 51,365 7,419 58,784
Transportation 3,295 7,729 11,024
Foreign exchange (gain)
loss and other (297) - (297)
General and administrative 15,120 16,093 31,213
----------------------------------------------------------------------------
69,483 762,158 831,641
----------------------------------------------------------------------------

Earnings before interest,
taxes, depletion,
depreciation, accretion
and other non-cash items 105,213 88,827 194,040
Other revenue
Unrealized (loss) gain on
financial derivative
instruments (2,696) (183) (2,879)
----------------------------------------------------------------------------

Other expenses
Depletion, depreciation and
accretion 113,570 22,311 135,881
Interest on bank debt 4,386 13,158 17,544
Interest and accretion on
convertible debentures 1,879 5,638 7,517
Unrealized foreign exchange
loss (gain) and other (917) 1,855 938
Non-cash unit based
compensation 3,011 4,094 7,105
Internal management charge (782) - (782)
Capital tax expense 888 - 888
Current and withholding tax
(recovery) expense 38 2,860 2,898
Future income tax (recovery)
expense (3) (65,475) 129,081 63,606
----------------------------------------------------------------------------
56,598 178,997 235,595
----------------------------------------------------------------------------
Net (loss) income for the
period from continuing
operations $ 45,919 $ (90,353) $ (44,434)
Net income from discontinued
operations (note 10) 41,328
----------------------------------------------------------------------------
Net loss for the period $ (3,106)
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(1) Included in the Midstream segment is product sales and service revenue
of $134.2 million associated with U.S. operations.
(2) Restated - see note 3.
(3) Future income tax (recovery) expense includes a charge of $104.7
million relating to the enactment of Bill C-52, Budget Implemetnation
Act 2007 by the Canadian government.


As at and for the six months ended June 30, 2007
--------------------------------------------------
Canadian Oil
and Natural
Gas Production Midstream (1) Total
----------------------------------------------------------------------------
Selected balance sheet items
Capital assets
Property, plant and
equipment net $ 1,693,767 $ 729,260 $ 2,423,027
Intangible assets - 182,464 182,464
Goodwill 417,614 100,409 518,023
Capital expenditures
Capital Expenditures 60,004 6,109 66,113
Corporate acquisitions 467,850 - 467,850
Oil and gas property
acquisitions, net 9,709 - 9,709
Goodwill additions 86,670 - 86,670
Working capital
Accounts receivable 76,197 185,345 261,542
Petroleum product inventory - 88,675 88,675
Accounts payable and
accrued liabilities 97,129 193,996 291,125
Long-term debt - revolving
term credit facilities 210,529 631,586 842,115
Long-term debt - convertible
debentures 69,612 208,837 278,449
Financial derivative
instruments (asset)
liability $ (5,955) $ 68,983 $ 63,028
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(1) Restated - see note 3.


Contact Information

  • Provident Energy Trust - Investor and Media Contact:
    Dallas McConnell
    Manager, Investor Relations
    (403) 231-6710
    Email: info@providentenergy.com
    or
    Corporate Head Office:
    2100, 250 - 2nd Street SW
    Calgary, Alberta T2P 0C1
    (403) 296-2233 or Toll Free: 1-800-587-6299
    (403) 262-8973 (FAX)
    Website: www.providentenergy.com