Provident Energy Trust
TSX : PVE.UN
NYSE : PVX

Provident Energy Trust

November 08, 2007 19:20 ET

Provident Energy Announces Third Quarter 2007 Results

CALGARY, ALBERTA--(Marketwire - Nov. 8, 2007) -

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

Provident Energy Trust (Provident) (TSX:PVE.UN) (NYSE:PVX) today announces third quarter 2007 results.

"Provident's third quarter results illustrate the value of our diversified energy portfolio for unitholders, as we increased production and maintained stable distributions in the face of persistently weak natural gas prices and a rising Canadian dollar," said Provident President and Chief Executive Officer, Tom Buchanan. "Our U.S. MLP, BreitBurn Energy Partners, is executing on its growth strategy with a major acquisition of long-life natural gas assets in the northeastern U.S. We also continue to strengthen the Canadian oil and gas production business, recently announcing a high quality oil acquisition in southeast Saskatchewan. In the Midstream business, strong operational performance and low natural gas prices enabled us to build low cost product inventories through the quarter that will be sold in the coming winter heating season."

Highlights

- Total funds flow from operations of $105 million ($0.43 per unit) for the quarter underpinned stable distributions. The negative impact of weak natural gas prices and the rising Canadian dollar in the third quarter were partially offset by strong oil prices, higher production and midstream frac spreads.

- Consolidated oil and gas production in the third quarter increased by 26 percent over 2006 to 38,800 boe per day, which includes the results of acquisition and drilling success in Canada and acquisitions in the U.S.

- Provident's MLP subsidiary, BreitBurn Energy Partners, L.P., announced a transforming U.S. $1.47 billion acquisition of long-life natural gas assets in Michigan, demonstrating the continuing success of the U.S. growth strategy.

- The Canadian Oil and Gas Production business again delivered strong production, up nine percent from the second quarter to 28,000 barrels of oil equivalent per day, reflecting the Dixonville acquisition and positive drilling results in Northwest Alberta. Dixonville oil production is increasing as expected as the drilling program is implemented.

- Midstream EBITDA of $47 million for the quarter was impacted by a realized opportunity cost from the commodity price risk management program of $23 million, reflecting the very strong frac spread ratio during the quarter. The Midstream plants and facilities are performing well, and the business is well positioned for a strong fourth quarter, assuming a normal winter heating season, as low-cost inventories produced in the third quarter are sold into strengthening product markets.

- The net loss for the quarter of $35 million ($0.14 per unit) is largely due to non-cash unrealized financial derivative losses on the commodity price risk management program of $56 million. Net earnings by quarter fluctuate considerably as all future unrealized gains or losses on the five year program are recorded against current period results.

- Declared distributions during the third quarter of 2007 of $88 million ($0.36 per unit), representing a sustained monthly distribution of $0.12 per unit for the last 47 months.



Consolidated financial highlights

Consolidated
($ 000s except Three months ended Nine months ended
per unit data) September 30, September 30,
----------------------------------------------------------------------------
% %
2007 2006 Change 2007 2006 Change
----------------------------------------------------------------------------

Revenue (net of
royalties and
financial
derivative
instruments) $ 533,249 $ 661,022 (19) $1,625,392 $ 1,639,167 (1)
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Funds flow
from COGP
operations(1) $ 47,143 $ 41,315 14 $ 145,585 $ 136,754 6

Funds flow
from USOGP
operations
(1)(3) 25,656 20,156 27 43,784 49,397 (11)

Funds flow
from
Midstream
operations(1) 32,350 58,618 (45) 101,323 123,834 (18)
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Total funds
flow from
operations(1) $ 105,149 $ 120,089 (12) $ 290,692 $ 309,985 (6)
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Per weighted
average
unit - basic $ 0.43 $ 0.61 (30) $ 1.30 $ 1.61 (19)

Per weighted
average
unit -
diluted(2) $ 0.43 $ 0.57 (25) $ 1.30 $ 1.58 (18)

Distributions
to unitholders $ 87,782 $ 70,970 24 $ 244,289 $ 207,892 18

Per unit $ 0.36 $ 0.36 - $ 1.08 $ 1.08 -

Percent of
funds flow
from operations
paid out as
declared
distributions(4) 89% 59% 51 88% 67% 31

Net (loss)
income(5) $ (35,005) $ 120,850 - $ (38,111) $ 166,421 -

Per weighted
average
unit - basic $ (0.14) $ 0.61 - $ (0.17) $ 0.87 -

Per weighted
average
unit -
diluted(2) $ (0.14) $ 0.58 - $ (0.17) $ 0.86 -

Capital
expenditures $ 54,317 $ 38,254 42 $ 153,757 $ 129,522 19

Capitol
Energy
acquisition $ - $ - $ 467,850 $ -

Oil and gas
property
acquisitions,
net $ 2,260 $ 472,731 $ 262,413 $ 472,947

Weighted
average
trust units
outstanding
(000s)
- Basic 243,600 197,156 24 224,174 192,180 17
- Diluted(2) 243,775 220,362 11 224,349 199,768 12
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Consolidated
----------------------------------------------------------------------------
As at As at
September 30, December 31,
($ 000s) 2007 2006 % Change
----------------------------------------------------------------------------
Capitalization
Long-term debt $1,217,136 $ 988,785 23
Unitholders' equity $1,634,459 $1,542,974 6
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(1) Represents cash flow from operations before changes in working capital
and site restoration expenditures.
(2) Includes dilutive impact of unit options, exchangeable shares and
convertible debentures.
(3) Year-to-date 2007 funds flow from USOGP operations includes $13.8
million (2006 - $4.9 million) of payments related to unit based
compensation expensed in the 2006 fiscal year and paid in 2007.
(4) Calculated as distributions to unitholders divided by funds flow from
operations less distributions to non-controlling interests of $13.7
million year-to-date and $6.6 million for the quarter (2006 - $1.8
million and $0.7 million, respectively).
(5) Net (loss) income for the nine months ended September 30, 2007 includes
a future income tax charge of $105.7 million relating to the enactment
of Bill C-52, Budget Implementation Act 2007 by the Canadian government.


Operational highlights

Consolidated Three months ended Nine months ended
September 30, September 30,
----------------------------------------------------------------------------
% %
2007 2006 Change 2007 2006 Change
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Oil and Gas
Production

Daily
production

Light/medium
crude oil (bpd) 19,289 13,955 38 16,323 14,185 15

Heavy oil (bpd) 2,324 2,004 16 1,973 2,125 (7)

Natural gas
liquids (bpd) 1,281 1,326 (3) 1,356 1,443 (6)

Natural gas
(mcfpd) 95,588 80,991 18 94,505 79,792 18
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Oil equivalent
(boed)(1) 38,825 30,784 26 35,403 31,052 14
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Average
realized price
(before
realized
financial
derivative
instruments)

Light/medium
crude oil
($/bbl) $ 64.59 $ 62.95 3 $ 60.89 $ 62.22 (2)

Heavy oil
($/bbl) $ 45.34 $ 48.15 (6) $ 41.39 $ 40.10 3

Corporate oil
blend
($/bbl) $ 62.52 $ 61.10 2 $ 58.76 $ 59.34 (1)

Natural gas
liquids
($/bbl) $ 55.22 $ 52.03 6 $ 52.11 $ 53.40 (2)

Natural gas
($/mcf) $ 4.95 $ 5.88 (16) $ 6.54 $ 6.64 (2)
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Oil equivalent
($/boe)(1) $ 48.82 $ 49.40 (1) $ 49.75 $ 50.72 (2)
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Field netback
(before
realized
financial
derivative
instruments)
($/boe) $ 26.08 $ 28.26 (8) $ 27.34 $ 29.39 (7)

Field netback
(including
realized
financial
derivative
instruments)
($/boe) $ 26.12 $ 28.17 (7) $ 27.56 $ 29.01 (5)
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Midstream

Midstream NGL
sales volumes
(bpd) 112,386 114,839 (2) 115,664 115,228 -

EBITDA
(000s)(2) $ 47,425 $ 65,958 (28) $136,252 $145,209 (6)
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(1) Provident reports oil equivalent production converting natural gas to
oil on a 6:1 basis.
(2) EBITDA is earnings before interest, taxes, depletion, depreciation,
accretion and other non-cash items. See "Reconciliation of non-GAAP
measures".


Management's discussion and analysis

The following analysis dated November 8, 2007 provides a detailed explanation of Provident Energy Trust's ("Provident's") operating results for the three and nine months ended September 30, 2007 compared to the same time periods in 2006 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 three key business segments: Canadian crude oil and natural gas production ("COGP"), United States crude oil and natural gas production, ("USOGP") and Midstream. Provident's COGP business produces crude oil and natural gas from seven core areas in the western Canadian sedimentary basin. USOGP produces crude oil and natural gas in California, Wyoming, Texas, and Florida, U.S.A. The Midstream business unit operates in Canada and the U.S.A. and extracts, processes, markets, transports and offers storage of natural gas liquids within the integrated facilities at Younger in British Columbia, Redwater and Empress in Alberta, Kerrobert in Saskatchewan, Sarnia in Ontario, Superior in Wisconsin and Lynchburg in Virginia.

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

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

Third quarter and nine months ended September 30, 2007 highlights

The third quarter highlights section provides commentary for the third quarter and for the nine months ended September 30, 2007 results compared to the corresponding periods in 2006.



Consolidated funds flow from operations and cash distributions

Consolidated
($ 000s except Three months ended Nine months ended
per unit data) September 30, September 30,
----------------------------------------------------------------------------
% %
2007 2006 Change 2007 2006 Change
----------------------------------------------------------------------------
Revenue,
Funds
Flow from
Operations
and
Distributions

Revenue (net
of royalties
and
financial
derivative
instruments $ 533,249 $ 661,022 (19) $1,625,392 $1,639,167 (1)
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Funds flow
from
operations $ 105,149 $ 120,089 (12) $ 290,692 $ 309,985 (6)

Per weighted
average unit
- basic $ 0.43 $ 0.61 (30) $ 1.30 $ 1.61 (19)

Per weighted
average unit
- diluted (1) $ 0.43 $ 0.57 (25) $ 1.30 $ 1.58 (18)
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Declared
distributions $ 87,782 $ 70,970 24 $ 244,289 $ 207,892 18
Per Unit 0.36 0.36 - 1.08 1.08 -

Percent of
funds
flow from
operations
distributed(2) 89% 59% 51 88% 67% 31
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(1) Includes dilutive impact of unit options, exchangeable shares and
convertible debentures.
(2) Calculated as declared distributions to unitholders divided by funds
flow from operations less distributions to non-controlling interests of
$13.7 million year-to-date and $6.6 million for the quarter (2006 - $1.8
million and $0.7 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.

Third quarter 2007 funds flow from operations was $105.1 million, 12 percent below the $120.1 million recorded in the third quarter of 2006. For the nine month period ended September 30, 2007 funds flow from operations was $290.7 million, six percent below the $310.0 million in the same period of 2006. COGP provided 45 percent of third quarter 2007 funds flow from operations, Midstream added 31 percent and USOGP generated the remaining 24 percent.

COGP 2007 third quarter funds flow from operations was $47.1 million, a 14 percent increase from the $41.3 million recorded in the comparable 2006 quarter. This increase was a result of higher crude oil and natural gas production due to the Capitol and Rainbow asset acquisitions and the internal development program, partially offset by lower realized natural gas prices, higher operating costs per boe and wider heavy oil differentials. For the nine month period ended September 30, 2007 COGP funds flow from operations was $145.6 million, a six percent improvement above the $136.8 million recorded in the comparable 2006 period.

The Midstream business unit added $32.4 million to third quarter 2007 funds flow from operations, 45 percent below the $58.6 million recorded in the comparable 2006 quarter, reflecting a seven percent reduction in gross operating margin, a $12.4 million increase in the realized loss on financial derivative instruments and higher interest and taxes. Typically in the Midstream business, the first and fourth quarters of the year generate considerably stronger funds flow from operations than the second and third quarters due to seasonality of product demand. For the nine months ended September 30, 2007, Midstream contributed $101.3 million to funds flow from operations, an 18 percent decrease from the $123.8 million in the comparable 2006 period. The decrease in Midstream funds flow from operations was largely due to a $15.0 million increase in realized losses on financial derivative instruments year-to-date 2007 over 2006 combined with higher general and administrative costs, interest and taxes, partially offset by a six percent increase in gross operating margin. See "Commodity price risk management" for detail regarding the losses on financial derivative instruments.

Funds flow from operations from USOGP operations in the third quarter of 2007 was $25.6 million, 27 percent above the $20.2 million in the comparable 2006 quarter. The increase is primarily due to two oil and gas property acquisitions in the second quarter of 2007. USOGP funds flow from operations for the nine months ended September 30, 2007 was $43.8 million, 11 percent below the $49.4 million in the comparable 2006 period. The decrease in funds flow from operations was primarily due to $13.8 million (2006 - $4.9 million) in cash payments in 2007 for unit based compensation related to the 2006 fiscal year. The expenses were recorded as non-cash unit based compensation in 2006 and resulted in a decrease to funds flow from operations when paid in 2007.

Declared distributions in the third quarter of 2007 totaled $87.8 million compared to $71.0 million of declared distributions in 2006. This represented 89 percent and 59 percent of funds flow from operations, respectively, after distributions to non-controlling interests of $6.6 million (2006 - $0.7 million). On a segmented basis, the Midstream business, due to its low sustaining capital requirements, effectively contributed 95 percent of its funds flow from operations for distribution in the three months ended September 30, 2007. The remaining distributions were effectively contributed by the oil and natural gas production businesses representing 86 percent of its funds flow from operations in the third quarter of 2007.

Outlook

Management currently anticipates better financial results in the fourth quarter than the third quarter of 2007, as upstream production continues to increase and the midstream business enters what is typically the strongest quarter of the year. While persistent natural gas price weakness remains a concern for the upstream businesses, low gas prices have enabled the Midstream business to build inexpensive inventory. Crude oil prices are approaching record highs, although the rising Canadian dollar mitigates that gain. These offsetting factors illustrate the ability of Provident's diversified business to generate sustainable cash flow and stable distributions in spite of business environment volatility. The strong Canadian dollar is positive for U.S. unitholders, who see a resulting increase in distributions.

Long-term strategic planning remains a key focus for Provident management given the planned tax on income trust distributions that the Canadian federal government intends to implement beginning in 2011. The rules around the tax administration remain unclear, so it is difficult to estimate the impact on Provident with precision. While examining potential future scenarios, management's current focus is on ensuring day-to-day operational excellence and continuing to build growth opportunities within all three business units, so that each is a strong, competitive business in its own right.

The Canadian Oil and Gas Production business unit has had an excellent year, highlighted by strong drilling and production results and two acquisitions of high quality assets (the Dixonville acquisition in May and the recently announced southeast Saskatchewan acquisition). The current weakness in natural gas prices and uncertainty in the business environment due to impending trust taxation and the announced Alberta royalty changes are generating acquisition opportunities. Provident will continue to assess long life, high quality assets that fit with our current portfolio. With strong operational performance to date and the anticipated completion of the southeast Saskatchewan acquisition, Provident now expects full year 2007 COGP production to meet the high end of the current production guidance, which is 26,400 boed.

Provident's U.S. Oil and Gas Production business continues to grow, as BreitBurn Energy Partners L.P. takes advantage of its competitive cost of capital to pursue accretive acquisitions. The recent Quicksilver acquisition will vault the MLP into a leading position among the U.S. oil and gas master limited partnerships. While Provident's interest in the MLP has been reduced to 22 percent, the Trust benefits both from the increased market value of the MLP and from its projected increase in quarterly distributions. With two months of production anticipated from the Quicksilver assets in 2007, Provident now anticipates that total U.S. production for 2007 will exceed previous production guidance of 9,500 to 10,000 boed.

The Midstream business continues to generate strong EBITDA and funds flow, mitigated somewhat by significant opportunity costs from the commodity price risk management program in the current business environment of low natural gas prices and high oil prices. The business is very well positioned for the fourth quarter, as inventories of low-cost natural gas liquids have been building over the summer months for sale into the seasonally stronger markets for propane and butane. With strategically located long-life facilities, storage capacity, multiple transportation choices and in-house marketing expertise, the Midstream business has flexibility and optionality. Assuming that seasonal product demand follows typical patterns, the Midstream business remains on track to generate 2007 EBITDA generally comparable to that in 2006.

On October 25, 2007, the Alberta provincial government announced a proposed new royalty regime for Alberta oil and gas production, to take effect on January 1, 2009. While the new regime will generally increase royalties on conventional oil and gas production, it is also sensitive to commodity pricing and to production per well. Management expects that Provident's diversified portfolio will mitigate the impact of the new regime on the Trust, given that more than 60 percent of total funds flow from operations comes from midstream operations and operations outside Alberta. However, future drilling programs in Alberta may be impacted as Provident and partner companies reassess the economics of their Alberta assets.

Restatement of 2007 interim consolidated financial statements

In the third quarter of 2007, Provident determined that an adjustment was necessary principally due to commercial transactions within the Midstream segment that resulted in overstated inventory balances. Internal accounting controls identified the issue. Related cash settlements with third parties were not affected. Management has studied the systems and procedures involved and has taken remedial steps to strengthen the internal controls over these systems and procedures.

The effect of the restatement on the interim consolidated financial statements for the first and second quarters of 2007 is summarized below. There is no effect on 2006 or prior periods.



Effect on Effect on Effect on
the three the three the six
months ended months ended months ended
(000's) March 31, 2007 June 30, 2007 June 30, 2007
----------------------------------------------------------------------------

Increase in accounts receivable $ 3,138 $ 888 $ 4,026
(Decrease) in petroleum product
inventory (13,226) (8,095) (21,321)
Decrease in future income tax
liability 2,875 2,054 4,929
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(Decrease) in unitholders' equity $ (7,213) $ (5,153) $ (12,366)
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----------------------------------------------------------------------------

(Increase) in cost of goods sold $(10,088) $ (7,207) $ (17,295)
Decrease in future income tax expense 2,875 2,054 4,929
----------------------------------------------------------------------------
(Decrease) in net income $ (7,213) $ (5,153) $ (12,366)
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(Decrease) in net income per unit
- basic and diluted $ (0.04) $ (0.02) $ (0.05)
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----------------------------------------------------------------------------

Decrease in funds flow from
operations $(10,088) $ (7,207) $ (17,295)
Change in non-cash working capital 10,088 7,207 17,295

Percentage of funds flow from
operations distributed
- originally reported 82% 79% 80%
Percentage of funds flow from
operations distributed - restated 91% 85% 88%
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Taxation of trust income

In 2007, future income tax expense includes $105.7 million relating to the enactment of Bill C-52, Budget Implementation Act 2007 by the Canadian government. This bill contains legislation to tax publicly traded trusts including Provident. As a result of this legislation, the Trust is now required to record the future tax effect of the temporary differences on its flow through entities that are expected to reverse subsequent to 2010. The Trust has recorded the future income tax provision relating to this legislation as a rate change resulting in incremental future income tax expense of $105.7 million in 2007.

Until June 2007 the Trust had been reflecting the impact of certain taxable temporary differences in flow through entities at a nil tax rate on the assumption that the Trust would make sufficient tax deductible cash distributions to unitholders such that the Trust's taxable income would be nil for the foreseeable future. The new legislation limits the tax deductibility of cash distributions such that income taxes may become payable in the future.

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

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

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

The Trust has approximately $1.3 billion in tax pools available to claim against taxable income. Provident plans to manage discretionary tax pool claims to defer payment of current taxes as long as possible. Provident has made estimates of future current taxability based on a number of assumptions including: future product prices; future production and sales; future operating and product costs; future general and administrative costs; future capital expenditures; and general business conditions. Using these assumptions about future events which may or may not occur, Provident estimates that:

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

- current taxes for midstream operations would occur in 2011.



Net (loss) income

Consolidated Three months ended Nine months ended
September 30, September 30,
----------------------------------------------------------------------------
($ 000s except % %
per unit data) 2007 2006 Change 2007 2006 Change
----------------------------------------------------------------------------

Net (loss)
income $ (35,005) $ 120,850 - $ (38,111) $ 166,421 -

Per weighted
average unit
- basic (1) $ (0.14) $ 0.61 - $ (0.17) $ 0.87 -

Per weighted
average unit
- diluted(2) $ (0.14) $ 0.58 - $ (0.17) $ 0.86 -
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(1) Based on weighted average number of trust units outstanding.
(2) Based on weighted average number of trust units outstanding including
the dilutive impact of the unit option plan, exchangeable shares and
convertible debentures.


Net loss for the third quarter of 2007 was $35.0 million compared to $120.9 million of net income in the comparable 2006 quarter. On a consolidated basis, favorable operating results were more than offset by a $141.0 million change in unrealized loss on financial derivative instruments and increased depletion, depreciation and accretion.

The COGP business segment's net loss was $17.8 million, a decrease of $40.4 million compared to the 2006 third quarter net income of $22.6 million. The decrease was mainly due to increased depletion, depreciation, and accretion resulting from the acquisitions of Capitol on June 19, 2007 and the Rainbow assets on August 31, 2006, and unrealized losses on financial derivative instruments compared to unrealized gains in the third quarter of 2006, partially offset by increased operating earnings.

The Midstream segment's net loss was $8.6 million in the third quarter of 2007 as compared to $82.7 million net income in the third quarter of 2006. The loss was primarily attributable to the impact of the commodity price risk management program. The third quarter of 2007 saw a $12.4 million increase in realized losses on financial derivative instruments. As well, the $30.9 million unrealized losses on financial derivative instruments in the third quarter of 2007 represents a $78.3 million change from the $47.4 million unrealized gain in the third quarter of 2006.

In the third quarter of 2007, USOGP's net loss was $8.6 million as compared to 2006 third quarter net income of $15.5 million. Increased operating earnings were more than offset by a $23.9 million unrealized loss on financial derivative instruments in the third quarter of 2007, compared to a $23.0 million unrealized gain in the third quarter of 2006. The 2007 unrealized loss includes $12.0 million associated with deal contingent, natural gas, 3.5 year, commodity swaps entered into to support the U.S. acquisition, which closed on November 1, 2007.

The significant swing in Provident's net income year-over-year illustrates the extent to which quarterly 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

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



EBITDA Reconciliation Three months ended Nine months ended
September 30, September 30,
----------------------------------------------------------------------------
% %
2007 2006 Change 2007 2006 Change
----------------------------------------------------------------------------

EBITDA $ 129,948 $ 133,708 (3) $ $349,294 354,970 (2)

Adjusted for:

Dilution gain - - - 98,592 - -

Interest
and
non-cash
expenses
excluding
unrealized
(loss)
gain on
financial
derivative
instruments
and dilution
gain (126,661) (76,974) 65 (317,883) (218,687) 45

Unrealized
(loss)
gain on
financial
derivative
instruments (56,242) 84,737 - (80,314) (19,021) 322
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(Loss)
income
before
taxes and
non-
controlling
interests $ (52,955) $ 141,471 - $ 49,689 $ 117,262 (58)
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Reconciliation
of funds flow
from operations Three months ended Nine months ended
to distributions September 30, September 30,
----------------------------------------------------------------------------
% %
2007 2006 Change 2007 2006 Change
----------------------------------------------------------------------------
Cash
provided by
operating
activities $ 90,655 $ 69,928 30 $ 327,125 $ 251,460 30

Change in
non-cash
operating
working
capital 13,904 48,904 (72) (38,773) 55,117 -

Site
restoration
expenditures 590 1,257 (53) 2,340 3,408 (31)
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Funds flow
from operations 105,149 120,089 (12) 290,692 309,985 (6)

Distributions
to non-
controlling
interests (6,583) (698) 843 (13,722) (1,808) 659

Cash
retained for
financing and
investing
activities (10,784) (48,421) (78) (32,681) (100,285) (67)
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Distributions
to unitholders 87,782 70,970 24 244,289 207,892 18

Accumulated
cash
distributions,
beginning
of period 1,083,332 780,282 39 926,825 643,360 44
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Accumulated
cash
distributions,
end of period $1,171,114 $851,252 38 $1,171,114 $ 851,252 38
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Cash
distributions
per unit $ 0.36 $ 0.36 - $ 1.08 $ 1.08 -
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Taxes

Consolidated Three months ended Nine months ended
September 30, September 30,
----------------------------------------------------------------------------
($ 000s) % %
2007 2006 Change 2007 2006 Change
----------------------------------------------------------------------------

Capital tax
expense $ 2,364 $ 259 813 $ 3,252 $ 862 277

Current and
withholding
tax expense
(recovery) 3,493 (1,328) - 6,623 4,396 51

Future
income tax
(recovery)
expense (19,302) 19,406 - 88,080 (55,569) -
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$ (13,445) $ 18,337 - $ 97,955 $ (50,311) -
----------------------------------------------------------------------------


For the nine months ended September 30, 2007, the total income tax expense was $98.0 million. Based on year-to-date income before taxes and non-controlling interests of $49.7 million, the expected income tax expense was $16.2 million. The main reason for the larger than expected income tax expense is $105.7 million of future income taxes recorded as a result of the enactment of legislation to tax publicly traded trusts in 2011 (see "Taxation of trust income"). The offsetting difference between the expected expense and the total tax expense is primarily a result of deductions allowed when computing taxable income of the Trust for distributions made to unitholders. The Trust is a taxable entity under Canadian income tax law and is currently taxable only on income that is not distributed or distributable to the unitholders until 2011, when the new tax on distributions is in 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 third quarter totaled $2.4 million, an increase from the $0.3 million expense recorded in the third quarter of 2006, and $3.3 million year-to-date, compared to $0.9 million year-to-date for 2006. The increase is due to greater production subject to the Saskatchewan resource surcharge as well as adjustments made upon filing of tax returns.

The current and withholding tax expense of $3.5 million in the third quarter of 2007 compares to a recovery of $1.3 million in the third quarter of 2006. The majority of these taxes arise from Provident's U.S.-based operations and 2007 withholding taxes reflect additional distributions in the third quarter of 2007. For the nine months ended September 30, 2007, current and withholding taxes total $6.6 million, compared with $4.4 million in 2006. The increase in current taxes was due to U.S.-based Midstream operations.

The 2007 third quarter future income tax recovery of $19.3 million compares to an expense of $19.4 million in the third quarter of 2006. The recovery is primarily a result of increased tax loss carry forwards generated from interest and royalties charged by the Trust to its subsidiaries. For the nine months ended September 30, 2007, future income tax expense was $88.1 million, compared with a recovery of $55.6 million in 2006. The 2007 expense includes $105.7 million relating to the second quarter enactment of legislation to tax publicly traded trust in 2011.



Provident's tax pools available to shelter future income as at September
30, 2007 are estimated as follows:

As at September 30, 2007
----------------------------------------------------------------------------
($ 000s) COGP USOGP (1) Midstream Total
----------------------------------------------------------------------------
Intangibles $ 490,000 $ 60,000 $ - $ 550,000
Tangibles 260,000 65,000 280,000 605,000
Non-capital losses 120,000 - 65,000 185,000
----------------------------------------------------------------------------
$ 870,000 $ 125,000 $ 345,000 $1,340,000
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(1) Non-Canadian tax pools


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


Interest expense

Consolidated Three months ended Nine months ended
September 30, September 30,
----------------------------------------------------------------------------
($ 000s, except) % %
as noted) 2007 2006 Change 2007 2006 Change
----------------------------------------------------------------------------
----------------------------------------------------------------------------

Interest on
bank debt $ 13,445 $ 9,334 44 $ 32,066 $ 23,504 36

Weighted-
average
interest
rate on
bank debt 5.6% 5.6% - 5.5% 5.3% 4

Interest on
8.75%
convertible
debentures 466 626 (26) 1,605 2,016 (20)

Interest on
8.0%
convertible
debentures 502 632 (21) 1,471 1,957 (25)

Interest on
6.5%
convertible
debentures 1,609 1,610 - 4,827 4,828 -

Interest on
6.5%
convertible
debentures 2,437 2,438 - 7,311 7,278 -
----------------------------------------------------------------------------

Total cash
interest $ 18,459 $ 14,640 26 $ 47,280 $ 39,583 19
----------------------------------------------------------------------------
----------------------------------------------------------------------------

Weighted
average
interest
rate on all
long-term
debt 5.9% 6.0% (2) 5.8% 5.8% -

Debenture
accretion
and other
non-cash
interest
expense 1,786 666 168 5,416 2,040 165
----------------------------------------------------------------------------

Total
interest
expense $ 20,245 $ 15,306 32 $ 52,696 $ 41,623 27
----------------------------------------------------------------------------
----------------------------------------------------------------------------


Interest on bank debt increased in 2007 compared to 2006 due to increased capitalization including debt levels, largely resulting from the Rainbow asset acquisition in the third quarter of 2006 and the Capitol acquisition in the second quarter of 2007.

Commodity price risk management program

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

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

In the Midstream business, production margins are affected by the spread between the purchase cost of natural gas and sales price of propane, butane and condensate. Financial market liquidity may not provide sufficient or adequate opportunity to directly hedge propane, butane and condensate prices over the longer term. Prices for propane, butane and condensate historically have correlated with prices for crude oil. As a consequence, Provident has entered into natural gas and crude oil financial derivative contracts through 2012 in order to protect operating margins in the Midstream business. Short term financial derivative instruments directly fixing propane and butane prices have also been executed.



Activity in the Third Quarter

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

COGP

Volume Effective
Year Product (Buy)/Sell Terms Period
----------------------------------------------------------------------------
2007 Crude 525 Bpd Puts US $64.57 per bbl October 1 -
Oil December 31
125 Bpd Participating Swap US $65.00 per bbl October 1 -
(max to 95% above the floor price) December 31

2008 250 Bpd Puts US $63.75 per bbl January 1 -
December 31
250 Bpd Participating Swap US $60.00 per bbl January 1 -
(75.3% above the floor price) December 31
125 Bpd Participating Swap US $65.00 per bbl January 1 -
(50.4% above the floor price) December 31
325 Bpd Participating Swap US $67.20 per bbl July 1 -
(70% above the floor price) December 31

2009 125 Bpd Participating Swap US $60.00 per bbl January 1 -
(60% above the floor price) December 31
425 Bpd Participating Swap US $62.50 per bbl January 1 -
(55.2% above the floor price) December 31

2007 Natural 7,750 Gjpd Puts Cdn $4.78 per gj October 1 -
Gas October 31
1,000 Gjpd Participating Swap Cdn $5.00 per gj October 1 -
(51% above the floor price) October 31

2008 1,000 Gjpd Puts Cdn $6.00 per gj January 1 -
March 31
5,000 Gjpd Participating Swap Cdn $6.48 per gj January 1 -
(max up to 100% above the floor price) March 31
2,000 Gjpd Participating Swap Cdn $6.00 per gj January 1 -
(max up to 85% above the floor price) October 31
2,000 Gjpd Participating Swap Cdn $6.00 per gj April 1 -
(56% above the floor price) October 31
1,000 Gjpd Participating Swap Cdn $6.75 per gj April 1 -
(51% above the floor price) December 31
1,000 Gjpd Participating Swap Cdn $7.00 per gj April 1 -
(max up to 85% above the floor price) December 31
1,000 Gjpd Participating Swap Cdn $6.50 per gj November 1 -
(50% above the floor price) December 31
1,000 Gjpd Participating Swap Cdn $6.50 per gj November 1 -
(max up to 90% above the floor price) December 31
2,000 Gjpd Participating Swap Cdn $6.75 per gj November 1 -
(max up to 90% above the floor price) December 31
2,000 Gjpd Participating Swap Cdn $7.00 per gj November 1 -
(max up to 85% above the floor price) December 31
2,000 Gjpd Participating Swap Cdn $7.50 per gj November 1 -
(max up to 100% above the floor price) December 31

2009 1,000 Gjpd Participating Swap Cdn $6.50 per gj January 1 -
(50% above the floor price) March 31
1,000 Gjpd Participating Swap Cdn $6.50 per gj January 1 -
(max up to 90% above the floor price) March 31
1,000 Gjpd Participating Swap Cdn $6.75 per gj January 1 -
(51% above the floor price) March 31
2,000 Gjpd Participating Swap Cdn $6.75 per gj January 1 -
(max up to 90% above the floor price) March 31
1,000 Gjpd Participating Swap Cdn $7.00 per gj January 1 -
(max up to 85% above the floor price) March 31
2,000 Gjpd Participating Swap Cdn $7.00 per gj January 1 -
(max up to 85% above the floor price) March 31
2,000 Gjpd Participating Swap Cdn $7.50 per gj January 1 -
(max up to 100% above the floor price) March 31
----------------------------------------------------------------------------
----------------------------------------------------------------------------

USOGP
Volume Effective
Year Product (Buy)/Sell Terms Period
----------------------------------------------------------------------------
2007 Crude 125 Bpd Participating Swap US $62.50 per bbl October 1 -
Oil (max up to 95% above the floor price) December 31
125 Bpd Participating Swap US $65.00 per bbl October 1 -
(92.1% above the floor price) December 31

2008 125 Bpd Participating Swap US $60.00 per bbl January 1 -
(78% above the floor price) December 31
125 Bpd Participating Swap US $65.00 per bbl January 1 -
(57.5% above the floor price) December 31
790 Bpd US $72.89 per bbl (10) January 1 -
December 31

2009 425 Bpd Participating Swap US $60.00 per bbl January 1 -
(61.45% above the floor price) December 31
679 Bpd US $71.38 per bbl (10) January 1 -
December 31
250 Bpd Participating Swap US $62.50 per bbl January 1 -
(67.25% above the floor price) December 31
500 Bpd US $72.25 per bbl April 1 -
June 30
250 Bpd US $72.47 per bbl October 1 -
December 31
250 Bpd Participating Swap US $60.00 per bbl October 1 -
(70% above the floor price) December 31
500 Bpd Participating Swap US $65.00 per bbl October 1 -
(54% above the floor price) December 31
500 Bpd Participating Swap US $65.00 per bbl October 1 -
(50% above the floor price) December 31

2010 609 Bpd US $70.42 per bbl (10) January 1 -
December 31
250 Bpd Participating Swap US $62.50 per bbl January 1 -
(56.20% above the floor price) December 31
250 Bpd Participating Swap US $60.00 per bbl January 1 -
(70% above the floor price) June 30
500 Bpd Participating Swap US $65.00 per bbl January 1 -
(50% above the floor price) June 30
250 Bpd US $72.47 per bbl January 1 -
June 30
542 Bpd US $72.05 per bbl January 1 -
July 31

2008 Natural 48,643 US $8.01 per mmbtu (11) January 1 -
Gas Mmbtu December 31

2009 44,071 US $8.01 per mmbtu (11) January 1 -
Mmbtu December 31

2010 40,471 US $8.01 per mmbtu (11) January 1 -
Mmbtu December 31

2011 40,400 US $8.01 per mmbtu (11) January 1 -
Mmbtu March 31
----------------------------------------------------------------------------
----------------------------------------------------------------------------

Midstream
Volume Effective
Year Product (Buy)/Sell Terms Period
----------------------------------------------------------------------------
2007 Crude (11,595)Bpd US $73.54 per bbl (4) October 1 -
Oil December 31
1,613 Bpd US $77.53 per bbl (9) October 1 -
October 31
1,667 Bpd US $77.66 per bbl (9) November 1 -
November 30
806 Bpd US $77.97 per bbl (9) December 1 -
December 31
Natural 2,500 Gjpd Cdn $6.11 per gj (9) November 1 -
Gas November 30
Propane 11,543 Bpd US $1.2257 per gallon (4) (6) October 1 -
December 31
1,630 Bpd US $1.2184 per gallon (6) (9) October 1 -
December 31
Normal 815 Bpd US $1.4727 per gallon (7) (9) October 1 -
Butane December 31
2,450 Bpd US $1.4299 per gallon (4) (7) October 1 -
December 31
ISO 2,010 Bpd US $1.425 per gallon (4) (8) October 1 -
Butane December 31

2008 Crude (845) Bpd US $74.64 per bbl (4) January 1 -
Oil March 31
Propane 850 Bpd US $1.2487 per gallon (4) (6) January 1 -
March 31
5,645 Bpd US $1.2829 per gallon (6) (9) January 1 -
February 29
Normal 150 Bpd US $1.4325 per gallon (4) (7) January 1 -
Butane March 31
ISO 150 Bpd US $1.4453 per gallon (4) (8) January 1 -
Butane March 31

2009 Crude 712 Bpd Cdn $74.21 per bbl January 1 -
Oil August 31
1,000 Bpd Participating Swap US $63.13 per bbl July 1 -
(56% above the floor price) August 31
Natural (5,930) Cdn $7.32 per gj January 1 -
Gas Gjpd August 31
Foreign Sell US $1,972,561 per month July 1 -
Exchange @ 1.0245 (5) August 31

2010 Crude 1,552 Bpd Cdn $72.31 per bbl January 1 -
Oil August 31
500 Bpd Participating Swap Cdn $61.50 per bbl July 1 -
(50% above the floor price) August 31
Natural (9,687) Cdn $7.09 per gj January 1 -
Gas Gjpd August 31

2012 Crude 2,171 Bpd Cdn $72.61 per bbl January 1 -
Oil September 30
Natural (12,204) Cdn $7.02 per gj January 1 -
Gas Gjpd September 30
----------------------------------------------------------------------------
----------------------------------------------------------------------------


Corporate
Volume Effective
Year Product (Buy)/Sell Terms Period
----------------------------------------------------------------------------
2007 Foreign Buy US $1,000,000 @ .9925 (5) October 5
Exchange

2007 Interest Pay fixed rate of 4.8852% - Receive July 1 -
Rate 3M CAD BA on Cdn $50MM Notional (12) December 31

2008 Interest Pay fixed rate of 4.8852% - Receive January 1 -
Rate 3M CAD BA on Cdn $50MM Notional (12) July 31
----------------------------------------------------------------------------
----------------------------------------------------------------------------

(1) The above table represents a number of transactions entered into over
an extended period of time.
(2) Natural Gas contracts are settled against AECO monthly index.
(3) Crude Oil contracts are settled against NYMEX WTI calendar average.
(4) Conversion of Crude Oil BTU hedges to liquids.
(5) US dollar hedge contracts settled against Bank of Canada noon rate
average.
(6) Propane contracts are settled against Belvieu C3 TET.
(7) Normal Butane contracts are settled against Belvieu NC4 NON-TET.
(8) ISO Butane contracts are settled against Belvieu IC4 NON-TET.
(9) Midstream inventory hedges.
(10) Deal contingent commodity swap to support pending acquisition of
Quicksilver assets. Crude Oil contracts settle against NYMEX WTI.
(11) Deal contingent commodity swap to support pending acquisition of
Quicksilver assets. Natural Gas contracts settle against Natural Gas
- Michcon City Gate Inside FERC.
(12) Settles quarterly against 3M CAD BA interest rate.


A summary of all of Provident's contracts in place at September 30, 2007 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 during the third quarter of 2007. For comparative purposes the 2006 amounts are also summarized.

a) Crude oil

For the quarter ended September 30, 2007, Provident paid $5.8 million to settle various oil market based contracts on an aggregate volume of 1.0 million barrels. During the quarter ended September 30, 2006, Provident paid $2.9 million to settle various oil market based contracts on an aggregate volume of 0.7 million barrels. Strong oil prices during the quarter caused the opportunity cost on oil price risk management activities.

For the nine months ended September 30, 2007, Provident paid $2.4 million to settle various oil market based contracts on an aggregate volume of 2.3 million barrels. During the nine months ended September 30, 2006, Provident paid $7.0 million to settle various oil market based contracts on an aggregate volume of 1.6 million barrels.

It is estimated that if all contracts in place had been settled at September 30, 2007 an opportunity cost of $38.3 million (September 30, 2006 - $1.6 million) would have been incurred.

b) Natural Gas

For the quarter ended September 30, 2007, Provident received $5.9 million to settle various natural gas market based contracts on an aggregate volume of 4.6 million gj's. Weak natural gas prices during the quarter caused the gain on natural gas price risk management activities. For comparison, during the quarter ended September 30, 2006, Provident received $2.7 million to settle various natural gas market based contracts on an aggregate of 1.4 million gj's.

For the nine months ended September 30, 2007, Provident received $4.5 million to settle various natural gas market based contracts on an aggregate volume of 12.2 million gj's. For comparison, during the nine months ended September 30, 2006, Provident received $3.8 million to settle various natural gas market based contracts on an aggregate of 4.8 million gj's.

It is estimated that if contracts in place had been settled at September 30, 2007 an opportunity gain of $3.5 million (September 30, 2006 - $9.1 million) would have been incurred.

c) Midstream

For the quarter ended September 30, 2007 Provident received $5.2 million (2006 - paid $2.5 million) to settle Midstream oil market based contracts on an aggregate volume of 0.3 million barrels (2006 - 0.7 million barrels) and paid $19.5 million (2006 - $9.7 million) to settle Midstream natural gas market based contracts on an aggregate volume of 6.8 million gj's (2006 - 5.4 million gj's). A strong "frac spread ratio" between low natural gas prices and high crude oil prices caused this net opportunity cost. In addition, for the third quarter of 2007, Provident paid $9.0 million (2006 - received $1.2 million) to settle Midstream NGL market based contracts on an aggregate volume of 1.7 million barrels (2006 - 0.3 million barrels).

For the nine months ended September 30, 2007 Provident received $17.7 million (2006 - paid $4.2 million) to settle Midstream oil market based contracts on an aggregate volume of 0.8 million barrels (2006 - 1.2 million barrels) and paid $31.9 million (2006 - $18.3 million) to settle Midstream natural gas market based contracts on an aggregate volume of 18.7 million gj's (2006 - 10.3 million gj's). In addition, Provident paid $21.6 million (2006 - received $1.7 million) to settle Midstream NGL market based contracts on an aggregate volume of 4.8 million barrels (2006 - 0.7 million barrels).

It is estimated that if contracts in place had been settled at September 30, 2007 an opportunity cost of $99.9 million (September 30, 2006 - $40.1 million) would have been incurred. These unrealized "mark-to-market" opportunity costs relate to positions with effective periods ranging from 2007 through 2012 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 September 30, 2007, Provident received $1.8 million to settle various foreign exchange based contracts (2006 - paid $0.3 million).

For the nine months ended September 30, 2007, Provident received $1.3 million to settle various foreign exchange based contracts (2006 - $0.5 million). The foreign exchange gains have been included in note 12 as a component of foreign exchange gain and other and allocated to their respective business segments.

It is estimated that if contracts in place had been settled at September 30, 2007 an opportunity gain of $0.8 million (September 30, 2006 - nil) would have been incurred.

e) Interest rate contracts

As at September 30, 2007 the estimated value of contracts in place settled at September 30 interest rates was an opportunity cost of $0.1 million (September 30, 2006 - nil).

Goodwill

Goodwill represents the excess of the cost of an acquired enterprise over the net of the amounts assigned to assets acquired and liabilities assumed. In the second quarter of 2007, the Capitol Energy acquisition resulted in additional goodwill of $86.7 million. In 2005, the Midstream NGL Acquisition resulted in goodwill of $100.4 million. Goodwill of $330.9 million arose from COGP acquisitions in 2002 and 2004.



Liquidity and capital resources

Consolidated
----------------------------------------------------------------------------
September December %
($ 000s) 30, 2007 31, 2006 Change
----------------------------------------------------------------------------
Long-term debt - revolving term credit
facility $ 942,495 $ 702,993 34
Long-term debt - convertible debentures 274,641 285,792 (4)
----------------------------------------------------------------------------
Total debt 1,217,136 988,785 23
----------------------------------------------------------------------------
----------------------------------------------------------------------------

Equity (at book value) 1,634,459 1,542,974 6
----------------------------------------------------------------------------
Total capitalization at book value $2,851,595 $2,531,759 13
----------------------------------------------------------------------------
----------------------------------------------------------------------------

Total debt as a percentage of total book
value capitalization 43% 39% 10
----------------------------------------------------------------------------
----------------------------------------------------------------------------


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

As at September 30, 2007, Provident held non-bank sponsored asset-backed commercial paper amounting to $7.0 million. These securities were previously classified as a component of cash and cash equivalent on the balance sheet. As at September 30, 2007 these securities have been classified as other current assets ($1.5 million) and investments ($5.5 million) 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 September 30, 2007 Provident had drawn on 71 percent of its term credit facilities that included a $1,125 million Canadian facility and a USD $212.7 million credit facility for USOGP. This compares to 63 percent drawn as at December 31, 2006.

At September 30, 2007 Provident had letters of credit guaranteeing Provident's performance under certain commercial and other contracts that totaled $32.9 million, increasing bank line utilization to 74 percent. The guarantees totaled $31.9 million at December 31, 2006.

Provident's working capital decreased by $52.3 million as at September 30, 2007 relative to December 31, 2006. This amount includes a $56.1 million increase in the current portion of financial derivative instruments, a $90.9 million increase in accounts payable and accrued liabilities, and a $2.6 million increase in distributions payable, partially offset by a $14.7 million increase in accounts receivable, a $50.9 million increase in inventory, and a $31.3 million increase in prepaid expenses and other current assets. Prepaid expenses and other assets at September 30, 2007 of $47.7 million includes a $34.9 million deposit related to the U.S. acquisition which closed on November 1, 2007.

Third quarter funds flow from operations in 2007 was $105.1 million. The ratio of debt to annualized third quarter funds flow from operations was 2.9 to one, as compared to third quarter 2006 debt to annualized funds flow from operations of 2.4 to one. The increase reflects debt issued in connection with the Capitol Energy acquisition.

Trust units

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

For the quarter ended September 30, 2007 the Trust issued 0.5 million units on conversion of convertible debentures (2006 - 0.8 million units). An additional 0.1 million units pursuant to the unit option plan were issued for the quarter ended September 30, 2007 (2006 - 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 third quarter and were issued or are to be issued representing proceeds of $14.8 million (2006 - 0.5 million units for proceeds of $8.3 million).

At September 30, 2007, management and directors held approximately 0.9 percent of the outstanding units.

Non-controlling interests - USOGP operations

A non-controlling interest arose from Provident's June 15, 2004 acquisition of 92 percent of BreitBurn Energy Company L.P. (BreitBurn) of Los Angeles, California. Additional investments since June 2004 by Provident in BreitBurn have reduced the non-controlling interest percentage at September 30, 2007 to approximately 4.1 percent (December 31, 2006 - 4.4 percent). At September 30, 2007, the carrying value of this non-controlling interest was $5.6 million.

In the second quarter of 2006, a USOGP subsidiary began a land development project with a partner. The subsidiary has a 20 percent interest, with the partner holding 80 percent. Because the subsidiary stands to receive a majority share of the future proceeds, Provident is consolidating the results in its statements, with non-controlling interest. Contributions by the non-controlling interest were $1.2 million in the third quarter (2006 - nil) and $3.8 million year-to-date (2006 - $2.7 million). At September 30, 2007, the carrying value of this non-controlling interest was $5.3 million.

In the fourth quarter of 2006, Provident's subsidiary, BreitBurn Energy Partners, L.P. (the "MLP") completed its initial public offering. BreitBurn transferred oil and gas properties comprising approximately half of its proved reserves and two thirds of its daily production to the MLP. The offering of 6.9 million common units at U.S. $18.50 per unit resulted in approximately 34 percent of the MLP held by partners not related to Provident. During the second quarter of 2007, the MLP issued 7.0 million common units to third parties for proceeds of $237.5 million. As a result of this transaction, Provident's interest in the MLP decreased from approximately 66 percent to approximately 50 percent, resulting in a dilution gain of $98.6 million recorded on the consolidated statement of operations. Provident continues to control and consolidate the MLP. The non-controlling interest balance increased by $138.9 million in the second quarter of 2007 reflecting the non-controlling interest ownership change from approximately 34 percent to approximately 50 percent. At September 30, 2007, the carrying value of this non-controlling interest was $171.9 million.



Three months ended Nine months ended
September 30, September 30,
----------------------------------------------------------------------------
Non-controlling interests
- USOGP ($ 000s) 2007 2006 2007 2006
----------------------------------------------------------------------------
Non-controlling interests,
beginning of period $205,365 $ 12,068 $ 81,111 $ 11,885
Net (loss) income attributable to
non-controlling interests (4,505) 1,929 (10,155) 547
Distributions to non-controlling
interests (6,583) (698) (13,722) (1,808)
Investments by non-controlling
interests 1,240 - 144,372 2,675
Foreign currency translation
adjustment (12,713) - (18,802) -
----------------------------------------------------------------------------
Non-controlling interests,
end of period $182,804 $ 13,299 $182,804 $ 13,299
----------------------------------------------------------------------------
Accumulated (loss) income
attributable to non-controlling
interests $ (4,641) $ 3,066 $ (4,641) $ 3,066
----------------------------------------------------------------------------
----------------------------------------------------------------------------


Capital expenditures and funding

Consolidated Three months ended Nine months ended
September 30, September 30,
----------------------------------------------------------------------------
($ 000s) % %
2007 2006 Change 2007 2006 Change
----------------------------------------------------------------------------
Capital
Expenditures
and Funding

Capital
Expenditures

Capital
expenditures
and
reclamation
fund
contributions $(54,907) $ (38,890) 41 $(156,097) $ (131,432) 19

Property
acquisitions,
net (2,260) (472,731) (100) (262,413) (472,947) (45)

Deposit on
acquisition (34,871) - - (34,871) - -

Corporate
acquisitions - - - (467,850) (2,300)20,241
----------------------------------------------------------------------------

Net capital
expenditures $(92,038) $(511,621) (82) $(921,231) $ (606,679) 52
----------------------------------------------------------------------------


Funded By

Funds flow
from
operations
net of
declared
distributions
to
unitholders
and non-
controlling
interest $ 10,784 $ 48,421 (78) $ 32,681 $ 100,285 (67)

Increase in
long-term
debt 71,067 290,225 (76) 200,159 288,395 (31)

Issue of
trust
units, net
of cost;
excluding
DRIP 471 213,501 (100) 361,118 216,924 66

DRIP
proceeds 14,777 8,348 77 35,357 25,494 39

Contributions
by non-
controlling
interests 1,153 - - 241,281 2,675 8,920

Change in
working
capital,
including
cash, sale
of assets and
change in
investments (6,214) (48,874) (87) 50,635 (27,094) -
----------------------------------------------------------------------------

Net capital
expenditure
funding $ 92,038 $511,621 (82) $ 921,231 $ 606,679 52
----------------------------------------------------------------------------
----------------------------------------------------------------------------


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) as well as contributions by non-controlling interests.

Provident expects to incur approximately $23 million in leasehold improvements and furniture and equipment associated with the head office move in 2008. To date, $6.8 million has been incurred. Of this amount, $4.4 million has been allocated to the COGP business unit and $2.4 million has been allocated to Midstream.

Acquisitions

On June 19, 2007, Provident acquired Capitol Energy Resources Ltd. ("Capitol") for cash consideration of $467.9 million. Capitol, a public oil and gas exploration and production company active in the Western Canadian sedimentary basin, had as its principal asset a long-life resource play at Dixonville, Alberta. This play is being exploited using horizontal wells and will be further developed using waterflood technology. The acquisition was financed by the issuance of 29,313,727 trust units at $12.75 per unit and Provident's credit facility.

In May 2007, BreitBurn Energy Partners L.P. (the "MLP") completed two oil and gas property acquisitions, one in Florida for cash consideration of USD $107.7 million and one in California for cash consideration of USD $92.4 million. The acquisitions were financed by the issue of units by the MLP to institutional investors. As a result of these unit issues, Provident's interest in the MLP has decreased from approximately 66 percent to approximately 50 percent. Provident continues to control and consolidate the MLP.

Non-cash unit based compensation

Non-cash unit based compensation includes expenses or recoveries associated with Provident's restricted and performance unit plan, unit option plan, unit appreciation rights and other unit based compensation plans. Provident accounts for the unit option plan using the fair value of the option at the time of issue. The other unit based compensation is recorded at the estimated fair value of the notional units granted. Compensation expense associated with the plans is deferred and recognized in earnings over the vesting period of each plan. The expense associated with each period is recorded as non-cash unit based compensation (a component of general and administrative expense). A portion is also allocated to operating expense. Provident recorded unit based compensation expense of $12.0 million for the quarter ended September 30, 2007 (2006 - $4.0 million) included primarily in general and administrative expense. Provident made payments in respect of unit based compensation of $0.7 million in the third quarter of 2007 (2006 - $1.1 million). For the nine months ended September 30, 2007, Provident recorded unit based compensation expense of $32.6 million (2006 - $15.9 million) and made related cash payments of $15.6 million (2006 - $5.7 million). At September 30, 2007, the current portion of the liability totaled $25.7 million (December 31, 2006 - $18.2 million) and the long-term portion totaled $23.3 million (December 31, 2006 - $16.3 million).

Subsequent events

U.S. acquisition closed

On November 1, 2007, the MLP closed its previously announced acquisition of natural gas, crude oil and related assets in Michigan, Indiana and Kentucky from Quicksilver Resources Inc. for USD $750 million in cash and approximately 21.3 million common units of the MLP. The acquisition is comprised of natural gas-weighted producing assets located primarily in the Michigan Antrim Shale. Daily production as at October 31, 2007 of approximately 90 million cubic feet of gas equivalent comes from over 5,000 gross producing wells. The cash portion of the purchase price will be funded by a private placement of new MLP units and bank debt. As a result of this transaction, Provident's interest in the MLP has decreased from approximately 50 percent to approximately 22 percent. Provident expects to record a related dilution gain in the fourth quarter of 2007. Provident continues to control the MLP through its 95.6 percent ownership of the general partner.

Canadian acquisition announced

On October 22, 2007, the Trust announced that it has reached an acquisition agreement with Triwest Energy Inc. (Triwest), a privately held company with oil assets in southeast Saskatchewan. Pursuant to the agreement, the Trust has made an offer to acquire all outstanding shares of Triwest for an exchange of approximately 6.25 million Trust units. The Trust will also assume Triwest's debt and working capital deficiency of approximately $13 million. Triwest operates approximately 1,300 barrels per day of oil production. The Trust expects the transaction to close near the end of November 2007.



COGP segment review

Crude oil and liquids price

The following prices are net of transportation expense.

COGP Three months ended Nine months ended
September 30, September 30,
----------------------------------------------------------------------------
($ per bbl) % %
2007 2006 Change 2007 2006 Change
----------------------------------------------------------------------------

Oil per
barrel
WTI (US$) $ 75.38 $ 70.48 7 $ 66.19 $ 68.22 (3)
Exchange
rate (from
US$ to Cdn$) $ 1.04 $ 1.12 (7) $ 1.10 $ 1.13 (3)
WTI
expressed
in Cdn$ $ 78.74 $ 78.94 - $ 73.13 $ 77.09 (5)
----------------------------------------------------------------------------
----------------------------------------------------------------------------

Realized
pricing
before
financial
derivative
instruments

Light/Medium
oil $ 61.17 $ 56.98 7 $ 58.28 $ 58.86 (1)
Heavy oil $ 45.34 $ 48.15 (6) $ 41.39 $ 40.10 3
Natural gas
liquids $ 55.47 $ 51.91 7 $ 52.30 $ 53.33 (2)
----------------------------------------------------------------------------
Crude oil
and natural
gas liquids $ 57.63 $ 54.53 6 $ 54.40 $ 54.29 -
----------------------------------------------------------------------------


In the third quarter of 2007, COGP's realized oil and natural gas liquids price, prior to the impact of financial derivative instruments, increased by six percent to $57.63 per barrel compared to $54.53 in the third quarter of 2006. The 2007 increase was a result of a seven percent increase in $US WTI crude oil price and increased pricing for light/medium oil relative to $US WTI partially offset by an unfavorable exchange rate and wider price differentials relative to WTI.



Natural gas price

The following prices are net of transportation expense.

COGP Three months ended Nine months ended
September 30, September 30,
----------------------------------------------------------------------------
($ per mcf) % %
2007 2006 Change 2007 2006 Change
----------------------------------------------------------------------------

AECO
monthly
index (Cdn$
per mcf) $ 5.61 $ 6.03 (7) $ 6.79 $ 7.19 (6)
Corporate
natural gas
price per
mcf before
financial
derivative
instruments
(Cdn$) $ 4.94 $ 5.90 (16) $ 6.54 $ 6.64 (2)
----------------------------------------------------------------------------
----------------------------------------------------------------------------


COGP's third quarter 2007 realized natural gas price, before financial derivative instruments, decreased 16 percent as compared to the third quarter of 2006, higher than the decrease in the benchmark AECO index price of seven percent. 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

COGP Three months ended Nine months ended
September 30, September 30,
----------------------------------------------------------------------------
% %
2007 2006 Change 2007 2006 Change
----------------------------------------------------------------------------
Daily
production
Crude oil
- Light/Medium
(bpd) 8,858 6,640 33 7,334 6,897 6
- Heavy (bpd) 2,324 2,004 16 1,973 2,125 (7)
Natural gas
liquids (bpd) 1,255 1,310 (4) 1,329 1,424 (7)
Natural gas
(mcfd) 93,511 78,560 19 92,309 77,410 19
----------------------------------------------------------------------------
Oil equivalent
(boed) (1) 28,022 23,047 22 26,021 23,348 11
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(1) Provident reports equivalent production converting natural gas to oil
on a 6:1 basis.


Production increased 22 percent to 28,022 boed during the third quarter of 2007 as compared to 23,047 boed in the comparable 2006 quarter. The increase in production was primarily a result of the Capitol acquisition on June 19, 2007 which increased both oil and gas production, and the August 31, 2006 Rainbow asset acquisition and subsequent drilling program which increased natural gas production.

Production for the third quarter of 2007 was weighted 56 percent natural gas, 36 percent light/medium crude oil and natural gas liquids, and eight percent heavy oil. Production over the nine months ended September 30, 2007 was weighted 59 percent natural gas, 33 percent light/medium crude and natural gas liquids, and eight percent heavy oil.

Drilling and optimization activity in COGP's core producing areas has proven successful. COGP executed a 32 well drilling program in Northwest Alberta early in 2007 accompanied by a facility and optimization program that realized production gains. Provident's newest core area, Dixonville, is delivering positive results as drilling to date has been 100 percent successful. In Dixonville, there are currently three drilling rigs in service and well completions and tie-ins are underway. Production from the oil pool, where Provident attributes the greatest value, experienced unanticipated down time in the third quarter, however, production is now in line with internal expectations. Non-associated gas production from neighboring fields is lower than expected due to natural declines. Dixonville production for the month of September averaged 3,864 boed and is on track to exit 2007 at a production rate of over 5,000 boed.



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

COGP
----------------------------------------------------------------------------
West
Three months ended Central Southern Northwest Southeast
September 30, 2007 Alberta Alberta Alberta Dixonville Saskatchewan
----------------------------------------------------------------------------

Daily production
Crude oil
- Light/Medium (bpd) 940 1,816 264 2,644 1,612
- Heavy (bpd) - - - - -
Natural gas liquids
(bpd) 1,021 116 85 16 -
Natural gas (mcfd) 27,792 21,614 28,274 5,743 155
----------------------------------------------------------------------------
Oil equivalent
(boed) (1) 6,593 5,534 5,061 3,618 1,638
----------------------------------------------------------------------------
----------------------------------------------------------------------------

COGP
----------------------------------------------------------------------------
Three months ended Southwest
September 30, 2007 Saskatchewan Lloydminster Other Total
----------------------------------------------------------------------------

Daily production
Crude oil
- Light/Medium (bpd) 310 1,256 16 8,858
- Heavy (bpd) - 2,324 - 2,324
Natural gas liquids (bpd) - 17 - 1,255
Natural gas (mcfd) 8,423 1,480 30 93,511
----------------------------------------------------------------------------
Oil equivalent (boed) (1) 1,714 3,843 21 28,022
----------------------------------------------------------------------------
----------------------------------------------------------------------------

COGP
----------------------------------------------------------------------------
West
Three months ended Central Southern Northwest Southeast
September 30, 2006 Alberta Alberta Alberta Dixonville Saskatchewan
----------------------------------------------------------------------------

Daily production
Crude oil
- Light/Medium (bpd) 995 2,130 80 - 1,800
- Heavy (bpd) - - - - -
Natural gas liquids
(bpd) 1,143 141 - - -
Natural gas (mcfd) 33,094 21,894 7,897 - 181
----------------------------------------------------------------------------
Oil equivalent
(boed) (1) 7,654 5,920 1,396 - 1,830
----------------------------------------------------------------------------
----------------------------------------------------------------------------

COGP
----------------------------------------------------------------------------
Three months ended Southwest
September 30, 2006 Saskatchewan Lloydminster Other Total
----------------------------------------------------------------------------

Daily production
Crude oil
- Light/Medium (bpd) 315 1,299 21 6,640
- Heavy (bpd) - 2,004 - 2,004
Natural gas liquids (bpd) - 24 2 1,310
Natural gas (mcfd) 14,150 1,344 - 78,560
----------------------------------------------------------------------------
Oil equivalent (boed) (1) 2,673 3,551 23 23,047
----------------------------------------------------------------------------
----------------------------------------------------------------------------

(1) Provident reports equivalent production converting natural gas to oil on
a 6:1 basis.

COGP
----------------------------------------------------------------------------
West
Nine months ended Central Southern Northwest Southeast
September 30, 2007 Alberta Alberta Alberta Dixonville Saskatchewan
----------------------------------------------------------------------------

Daily production
Crude oil
- Light/Medium (bpd) 974 1,911 253 1,006 1,617
- Heavy (bpd) - - - - -
Natural gas liquids
(bpd) 1,061 120 121 6 -
Natural gas (mcfd) 30,248 21,801 27,568 2,166 154
----------------------------------------------------------------------------
Oil equivalent
(boed) (1) 7,076 5,665 4,969 1,373 1,643
----------------------------------------------------------------------------
----------------------------------------------------------------------------

COGP
----------------------------------------------------------------------------
Nine months ended Southwest
September 30, 2007 Saskatchewan Lloydminster Other Total
----------------------------------------------------------------------------

Daily production
Crude oil
- Light/Medium (bpd) 309 1,249 15 7,334
- Heavy (bpd) - 1,973 - 1,973
Natural gas liquids (bpd) - 21 - 1,329
Natural gas (mcfd) 8,900 1,465 7 92,309
----------------------------------------------------------------------------
Oil equivalent (boed) (1) 1,792 3,487 16 26,021
----------------------------------------------------------------------------
----------------------------------------------------------------------------

COGP
----------------------------------------------------------------------------
West
Nine months ended Central Southern Northwest Southeast
September 30, 2006 Alberta Alberta Alberta Dixonville Saskatchewan
----------------------------------------------------------------------------

Daily production
Crude oil
- Light/Medium (bpd) 1,128 2,269 27 - 1,738
- Heavy (bpd) - - - - -
Natural gas liquids
(bpd) 1,266 136 - - -
Natural gas (mcfd) 35,690 23,431 2,661 - 167
----------------------------------------------------------------------------
Oil equivalent
(boed) (1) 8,342 6,310 471 - 1,766
----------------------------------------------------------------------------
----------------------------------------------------------------------------

COGP
----------------------------------------------------------------------------
Nine months ended Southwest
September 30, 2006 Saskatchewan Lloydminster Other Total
----------------------------------------------------------------------------

Daily production
Crude oil
- Light/Medium (bpd) 322 1,348 65 6,897
- Heavy (bpd) - 2,125 - 2,125
Natural gas liquids (bpd) - 22 - 1,424
Natural gas (mcfd) 13,972 1,320 169 77,410
----------------------------------------------------------------------------
Oil equivalent (boed) (1) 2,651 3,715 93 23,348
----------------------------------------------------------------------------
----------------------------------------------------------------------------

(1) Provident reports equivalent production converting natural gas to oil on
a 6:1 basis.
(2) Represents production from June 19, 2007 (date of Capitol Energy
Resources Ltd. acquisition).


Revenue and royalties

Three months ended Nine months ended
COGP September 30, September 30,
----------------------------------------------------------------------------
($ 000s except
per boe and % %
mcf data) 2007 2006 Change 2007 2006 Change
----------------------------------------------------------------------------

Oil
Revenue $ 59,542 $ 43,688 36 $ 138,989 $ 134,098 4
Realized loss
on financial
derivative
instruments (2,475) (670) 269 (3,230) (2,540) 27
Royalties (11,358) (9,209) 23 (26,720) (25,916) 3
----------------------------------------------------------------------------
Net revenue $ 45,709 $ 33,809 35 $ 109,039 $ 105,642 3
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Net revenue
(per barrel) $ 44.43 $ 42.51 5 $ 42.91 $ 42.89 -
Royalties as a
percentage of
revenue 19.1% 21.1% 19.2% 19.3%

Natural gas
Revenue $ 42,516 $ 42,624 - $ 164,860 $ 140,247 18
Realized gain
on financial
derivative
instruments 5,892 2,625 124 4,459 3,762 19
Royalties (9,662) (8,677) 11 (31,717) (30,520) 4
----------------------------------------------------------------------------
Net revenue $ 38,746 $ 36,572 6 $ 137,602 $ 113,489 21
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Net revenue
(per mcf) $ 4.50 $ 5.06 (11) $ 5.46 $ 5.37 2
Royalties as a
percentage of
revenue 22.7% 20.4% 19.2% 21.8%

Natural gas
liquids
Revenue $ 6,404 $ 6,258 2 $ 18,974 $ 20,734 (8)
Royalties (1,444) (1,678) (14) (4,799) (5,229) (8)
----------------------------------------------------------------------------
Net revenue $ 4,960 $ 4,580 8 $ 14,175 $ 15,505 (9)
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Net revenue
(per barrel) $ 42.96 $ 38.00 13 $ 39.07 $ 39.88 (2)
Royalties as a
percentage of
revenue 22.5% 26.8% 25.3% 25.2%

Total
Revenue $ 108,462 $ 92,570 17 $ 322,823 $ 295,079 9
Realized gain
on financial
derivative
instruments 3,417 1,955 75 1,229 1,222 1
Royalties (22,464) (19,564) 15 (63,236) (61,665) 3
----------------------------------------------------------------------------
Net revenue $ 89,415 $ 74,961 19 $ 260,816 $ 234,636 11
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Net revenue
(per boe) $ 34.68 $ 35.35 (2) $ 36.72 $ 36.81 -
Royalties as a
percentage of
revenue 20.7% 21.1% 19.6% 20.9%
----------------------------------------------------------------------------
----------------------------------------------------------------------------

Note: the above revenue, net revenue and net revenue per boe figures are
presented net of transportation expenses.


Quarter over quarter, 2007 COGP net revenue per boe declined by two percent to $34.68, while net revenue increased by 19 percent to $89.4 million. The higher revenue is largely due to increased oil and natural gas production from the Capitol acquisition on June 19, 2007 and increased natural gas production from the August 31, 2006 acquisition and subsequent drilling and optimization program at Northwest Alberta. Also contributing to the higher revenue were increased realized crude oil and natural gas liquids prices, partially offset by a decrease in realized natural gas prices, an unfavorable exchange rate, and wider differentials. Royalties, which are price sensitive and affected by production levels, decreased as a percentage of revenue to 20.7 percent in the third quarter of 2007 from 21.1 percent for the comparable quarter in 2006 primarily due to an oil royalty rate that was a lower percentage of higher realized crude oil prices offset by an increased natural gas royalty rate due to a one-time override royalty payment. The increase in realized gains on financial derivative instruments was a result of the decrease in the benchmark AECO gas price partially offset by a loss on oil contracts in a higher crude oil price environment. For the nine months ended September 30, 2007 net revenue per boe was $36.72 compared to $36.81 in the same period of 2006.



Production expenses

Three months ended Nine months ended
COGP September 30, September 30,
----------------------------------------------------------------------------
($ 000s, except % %
per boe data) 2007 2006 Change 2007 2006 Change
----------------------------------------------------------------------------

Production
expenses $ 31,378 $ 22,865 37 $ 82,743 $ 69,324 19
Production
expenses
(per boe) $ 12.17 $ 10.78 13 $ 11.65 $ 10.88 7
----------------------------------------------------------------------------
----------------------------------------------------------------------------


Third quarter 2007 production expenses increased 37 percent to $31.4 million from $22.9 million in the comparable 2006 quarter. The increase was mainly due to the 22 percent increase in production. On a per barrel basis, production expenses have increased to $12.17 per boe from $10.78 in the third quarter of 2006. For the third quarter of 2007, COGP experienced additional costs due to unexpected weather events. July and August 2007 had increased power costs from hot weather in Southern Alberta and West Central Alberta and increased road maintenance costs in Northwest Alberta due to significant wet weather. Year-to-date, production expenses increased 19 percent to $82.7 million from $69.3 million in 2006, reflecting an 11 percent increase in production. As well, the year-to-date increase is a result of the above activities and higher maintenance and service costs incurred during the first quarter of 2007, reflecting strong demand for services. Additional costs were incurred as a result of turnaround and facility optimization work primarily in Northwest Alberta. The higher production costs were partially offset by low costs at Dixonville.



Operating netback

Three months ended Nine months ended
COGP September 30, September 30,
----------------------------------------------------------------------------
% %
($ per boe) 2007 2006 Change 2007 2006 Change
----------------------------------------------------------------------------
Netback per boe
Gross
production
revenue $ 42.06 $ 43.66 (4) $ 45.45 $ 46.29 (2)
Royalties (8.71) (9.23) (6) (8.90) (9.67) (8)
Operating
costs (12.17) (10.78) 13 (11.65) (10.88) 7
----------------------------------------------------------------------------
Field
operating
netback 21.18 23.65 (10) 24.90 25.74 (3)
Realized gain
on financial
derivative
instruments 1.33 0.92 45 0.17 0.19 (11)
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Operating
netback after
realized
financial
derivative
instruments $ 22.51 $ 24.57 (8) $ 25.07 $ 25.93 (3)
----------------------------------------------------------------------------
----------------------------------------------------------------------------


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

Third quarter 2007 field operating netback decreased 10 percent to $21.18 per boe from $23.65 per boe in the comparable 2006 quarter. Year-to-date field operating netback of $24.90 per boe was three percent below the field operating netback for the same period in 2006. The decrease in field operating netback resulted from a higher production weighting to natural gas at a time of lower realized natural gas prices. As well, increased operating costs per boe offset lower royalties. Operating netbacks after realized financial derivative instruments decreased by eight percent to $22.51 per boe from $24.57 per boe for the quarter, and decreased by three percent to $25.07 from $25.93 year-to-date. The third quarter result reflects a realized gain on financial derivative instruments of $1.33 per boe compared to $0.92 realized gain in the comparable quarter in 2006.



General and administrative

Three months ended Nine months ended
COGP September 30, September 30,
----------------------------------------------------------------------------
($ 000s, except % %
per boe data) 2007 2006 Change 2007 2006 Change
----------------------------------------------------------------------------

Cash general
and
administrative $ 6,399 $ 6,490 (1) $ 21,519 $ 17,655 22
Non-cash unit
based
compensation 3,701 1,208 206 6,712 3,138 114
----------------------------------------------------------------------------
$ 10,100 $ 7,698 31 $ 28,231 $ 20,793 36

Cash general
and
administrative
(per boe) $ 2.48 $ 3.06 (19) $ 3.03 $ 2.77 9
----------------------------------------------------------------------------
----------------------------------------------------------------------------


Third quarter 2007 COGP cash general and administrative expenses decreased one percent to $6.4 million compared to $6.5 million in the third quarter of 2006. On a per barrel basis, cash general and administrative expenses decreased 19 percent to $2.48 per boe in 2007 compared to the $3.06 per boe in the third quarter of 2006. For the nine months ended September 30, 2007, cash general and administrative expenses were $3.03 per boe, compared to $2.77 per boe in 2006. The increase in cash general and administrative expenses reflects additional provisions for short-term incentive compensation reflecting the performance of the Trust in relation to established industry benchmarks, as well as increases in ongoing regulatory compliance and reporting costs.

Non-cash unit based compensation increased 206 percent to $3.7 million in the third quarter of 2007 from $1.2 million in the third quarter of 2006. Year-to-date, non-cash unit based compensation increased to $6.7 million from $3.1 million in 2006. The increase reflects increased employee incentive costs due to an additional annual award in 2007 and the total return performance of the Trust as measured against an industry peer group.



Capital expenditures

Three months ended Nine months ended
COGP September 30, September 30,
----------------------------------------------------------------------------
($ 000s) 2007 2006 2007 2006
----------------------------------------------------------------------------

Capital expenditures - by category
Geological, geophysical and land $ 1,819 $ 1,043 $ 3,900 $ 3,441
Drilling and recompletions 27,314 10,916 75,940 41,819
Facilities and equipment 2,783 1,108 7,551 4,988
Other capital 1,744 1,429 6,273 1,565
----------------------------------------------------------------------------
Total additions $ 33,660 $ 14,496 $ 93,664 $ 51,813
----------------------------------------------------------------------------
----------------------------------------------------------------------------

Capital expenditures - by area
West central Alberta $ 2,299 $ 2,393 $ 6,892 $ 7,312
Southern Alberta 4,711 5,703 11,201 14,619
Northwest Alberta 2,798 285 30,101 285
Dixonville 15,868 - 17,671 -
Southeast Saskatchewan 2,367 313 3,224 1,557
Southwest Saskatchewan 1,677 1,529 12,283 21,671
Lloydminster 2,157 3,013 5,852 5,524
Office and other 1,783 1,260 6,440 845
----------------------------------------------------------------------------
Total additions $ 33,660 $ 14,496 $ 93,664 $ 51,813
----------------------------------------------------------------------------
----------------------------------------------------------------------------

Property acquisitions, net $ 1,860 $472,731 $ 11,569 $474,955
----------------------------------------------------------------------------
----------------------------------------------------------------------------


In the third quarter of 2007, Provident's COGP business unit spent $27.3 million relating to drilling and recompletion activities, drilling 17.4 net wells with 100 percent success. In COGP's newest core area, Dixonville, $15.9 million was spent primarily on drilling and completion activities, consisting of 13.0 net wells. Northwest Alberta expenditures of $2.8 million were primarily on preparation work to start the 2007/2008 winter drilling program and associated facility work. Southern Saskatchewan expenditures of $4.0 million were mainly on drilling and completion activities targeting light oil in Southeast Saskatchewan. Southern Alberta expenditures of $4.7 million in the third quarter of 2007 consisted primarily of $4.0 million on drilling, completion and tie-ins from the drilling program including recompletion activities, $0.5 million on facility upgrades and $0.2 million on land and seismic activities. West Central Alberta expenditures of $2.3 million in the third quarter of 2007 mainly consisted of $1.6 million on non-operated drilling and completion activities and $0.7 million on facility work. In West Central Alberta, Provident continues to farm out its high risk exploration land which reduces the capital required to maintain its production declines. Lloydminster expenditures of $2.2 million in the third quarter of 2007 focused on optimization activities and facilities expenditures.

Net property acquisitions of $11.6 million in 2007 include additional working interests acquired in Northwest Alberta.



Depletion, depreciation and accretion (DD&A)

Three months ended Nine months ended
COGP September 30, September 30,
----------------------------------------------------------------------------
($ 000s, except % %
per boe data) 2007 2006 Change 2007 2006 Change
----------------------------------------------------------------------------

DD&A $ 72,288 $ 41,247 75 $ 185,858 $ 110,336 68
DD&A (per boe) $ 28.04 $ 19.45 44 $ 26.16 $ 17.31 51
----------------------------------------------------------------------------
----------------------------------------------------------------------------


The COGP DD&A rate of $28.04 per boe for the third quarter of 2007 increased by 44 percent compared to $19.45 per boe for the third quarter of 2006. The increase was primarily as a result of the Capitol acquisition on June 19, 2007 and the Rainbow asset acquisition in the third quarter 2006. Additions to property, plant and equipment of $1,183.1 million for the acquisitions included $185.7 million due to the recording of future income taxes. This, combined with higher net per boe reserve acquisition costs, resulted in increased per boe DD&A.

In the third quarter of 2007 accretion expense associated with asset retirement obligations was $0.6 million compared to $0.5 million in the comparable period of 2006. Year-to-date accretion expense was $1.8 million (2006 - $1.4 million).

USOGP segment review

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

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

In May 2007, the MLP completed two oil and gas property acquisitions, one in Florida for cash consideration of USD $107.7 million and one in California for cash consideration of USD $92.4 million. The acquisitions were financed by the issue of 7.0 million common units by the MLP to institutional investors at an average price of USD $31.58 per unit. As a result of these unit issues, Provident's interest in the MLP decreased from approximately 66 percent to approximately 50 percent, resulting in a dilution gain of $98.6 million recorded in the consolidated statement of operations in the second quarter of 2007. Provident continues to control and consolidate the MLP.

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



Crude oil, natural gas liquids and natural gas pricing

The following prices are net of transportation expenses.

Three months ended Nine months ended
USOGP September 30, September 30,
----------------------------------------------------------------------------
% %
2007 2006 Change 2007 2006 Change
----------------------------------------------------------------------------
Realized pricing
before
financial
derivative
instruments
Light/medium
oil and
natural gas
liquids (Cdn$
per bbl) $ 67.42 $ 68.37 (1) $ 63.01 $ 65.37 (4)
Natural Gas
(Cdn $ per
mcf) $ 5.09 $ 5.48 (7) $ 6.33 $ 6.84 (7)
----------------------------------------------------------------------------
----------------------------------------------------------------------------


Realized pricing of light/medium oil and natural gas liquids were one percent lower in the third quarter of 2007 when compared to the third quarter of 2006. The majority of USOGP oil production is light, sweet crude that attracts smaller differentials to benchmark prices relative to heavier blends. However, Wyoming crude, while generally of similar quality to Los Angeles Basin crude oil, trades at a significant discount to NYMEX WTI because of its distance from a major refining market and the fact that it is priced relative to the Bow River benchmark, which has historically traded at a discount to WTI.

Realized natural gas pricing before financial derivative instruments was down seven percent in the third quarter of 2007 when compared to the third quarter of 2006. The decrease was primarily associated with the decrease in Henry Hub pricing.



Production

Three months ended Nine months ended
September 30, September 30,
----------------------------------------------------------------------------
% %
USOGP 2007 2006 Change 2007 2006 Change
----------------------------------------------------------------------------

Daily production
- by product
Crude oil -
Light/Medium
(bpd) 10,431 7,315 43 8,989 7,288 23
Natural gas
liquids (bpd) 26 16 63 27 19 42
Natural gas
(mcfd) 2,077 2,431 (15) 2,196 2,382 (8)
----------------------------------------------------------------------------
Oil equivalent
(boed) (1) 10,803 7,737 40 9,382 7,704 22
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(1) Provident reports equivalent production converting natural gas to oil on
a 6:1 basis.


Three months ended Nine months ended
September 30, September 30,
----------------------------------------------------------------------------
% %
USOGP 2007 2006 Change 2007 2006 Change
----------------------------------------------------------------------------

Daily Production
- by area
(boed) (1)
Los Angeles 4,593 3,852 19 4,092 3,950 4
Santa Maria
- Orcutt 1,591 1,531 4 1,549 1,472 5
Wyoming 2,623 2,354 11 2,567 2,282 12
Texas 330 - - 359 - -
Florida 1,666 - - 815 - -
----------------------------------------------------------------------------
10,803 7,737 40 9,382 7,704 22
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(1) Provident reports equivalent production converting natural gas to oil on
a 6:1 basis.


USOGP production increased 3,066 boe per day or 40 percent in the third quarter of 2007 when compared to the third quarter of 2006. The increase is primarily attributable to acquisitions made by USOGP in 2007, which included fields in Los Angeles, Florida and Texas. Year-to-date production of 9,382 boed is an increase of 22 percent over year-to-date 2006 production of 7,704 boed, reflecting capital expenditures focused at Orcutt and Wyoming, in addition to the acquisitions. Third quarter 2007 production from the MLP was 8,193 boed, while production from BreitBurn was 2,610 boed.

Revenue and royalties

The following table outlines USOGP revenue and royalties by product line. The table excludes revenues earned from operating certain properties ($0.2 million in the third quarter of 2007 (2006 - $0.3 million) and $0.6 million in the nine months ended September 30, 2007 (2006 - $0.8 million)), on behalf of third parties. The table also excludes revenue from the sale of inventory acquired as part of the Florida acquisition in May 2007, amounting to $6.3 million in the three months ended September 30, 2007 and $6.5 million in the second quarter of 2007, or $12.8 million year-to-date.



Three months ended Nine months ended
USOGP September 30, September 30,
----------------------------------------------------------------------------
($ 000s, except
per boe and % %
mcf amounts) 2007 2006 Change 2007 2006 Change
----------------------------------------------------------------------------

Oil
Revenue $ 65,026 $ 46,137 41 $ 150,654 $ 130,408 16
Realized gain
(loss) on
financial
derivative
instruments (3,251) (2,195) 48 879 (4,397) -
Royalties (7,675) (4,526) 70 (16,875) (12,775) 32
----------------------------------------------------------------------------
Net revenue $ 54,100 $ 39,416 37 $ 134,658 $ 113,236 19
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Net revenue
(per bbl) $ 56.14 $ 58.57 (4) $ 56.37 $ 56.91 (1)
Royalties as a
percentage of
revenue 11.8% 9.8% 11.2% 9.8%

Natural gas
Revenue $ 972 $ 1,226 (21) $ 3,794 $ 4,447 (15)
Royalties (102) (149) (32) (488) (577) (15)
----------------------------------------------------------------------------
Net revenue $ 870 $ 1,077 (19) $ 3,306 $ 3,870 (15)
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Net revenue
(per mcf) $ 4.55 $ 4.82 (6) $ 5.51 $ 5.95 (7)
Royalties as a
percentage of
revenue 10.5% 12.2% 12.9% 13.0%

Natural gas
liquids
Revenue $ 106 $ 92 15 $ 316 $ 304 4
Royalties (7) (2) 250 (20) (6) 233
----------------------------------------------------------------------------
Net revenue $ 99 $ 90 10 $ 296 $ 298 (1)
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Net revenue
(per bbl) $ 41.39 $ 61.14 (32) $ 40.16 $ 57.45 (30)
Royalties as a
percentage of
revenue 6.6% 2.2% 6.3% 2.0%

Total
Revenue $ 66,104 $ 47,455 39 $ 154,764 $ 135,159 15
Realized gain
(loss) on
financial
derivative
instruments (3,251) (2,195) 48 879 (4,397) -
Royalties (7,784) (4,677) 66 (17,383) (13,358) 30
----------------------------------------------------------------------------
Net revenue $ 55,069 $ 40,583 36 $ 138,260 $ 117,404 18
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Net revenue
(per boe) $ 55.18 $ 57.01 (3) $ 55.39 $ 55.82 (1)
Royalties as a
percentage of
revenue 11.8% 9.9% 11.2% 9.9%
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Note: the above revenue, net revenue and net revenue per boe figures are
presented net of transportation expenses. Per boe figures are
calculated using sales volumes, which differ from production volumes
due to changes in inventory levels at the Florida properties, acquired
in the second quarter of 2007.


Revenue for the quarter ended September 30, 2007 was $66.1 million or 39 percent higher than the quarter ended September 30, 2006. The increase was primarily attributable to a 40 percent increase in production volumes in the third quarter of 2007 as compared to the third quarter of 2006. Net revenue is $55.1 million or 36 percent higher than the $40.6 million of net revenue in the third quarter 2006, reflecting a realized loss on financial derivative instruments in the third quarter of 2007. Royalties as a percentage of revenue have increased as royalties at the Wyoming, Texas and Florida properties are higher than those incurred at the Southern California operations. For the nine months ended September 30, 2007 revenue was 15 percent higher than the nine months ended September 30, 2006 primarily due to increases in sales volumes from the acquisitions. Net revenue for the nine months ended September 30, 2007 was 18 percent higher than the nine months ended September 30, 2006 due to a realized gain on financial derivative instruments in 2007 compared to a realized loss in 2006.



Production expenses

Three months ended Nine months ended
USOGP September 30, September 30,
----------------------------------------------------------------------------
($ 000s, except % %
per boe amounts) 2007 2006 Change 2007 2006 Change
----------------------------------------------------------------------------
Production
expenses $ 19,686 $ 12,771 54 $ 51,763 $ 36,474 42
Production
expenses
(per boe) $ 19.73 $ 17.94 10 $ 20.74 $ 17.34 20
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Note: Per boe figures are calculated using sales volumes, which differ from
production volumes due to changes in inventory levels at the Florida
properties, acquired in the second quarter of 2007.


Production expenses were $19.73 per boe in the third quarter of 2007, up $1.79 per boe or 10 percent from the third quarter of 2006. Production expenses were $20.74 per boe for the nine months ended September 30, 2007, an increase of 20 percent from the nine months ended September 30, 2006. This change reflects both the increase in utilities and other costs and services driven by the high commodity price environment as well as higher operating cost crude oil wells that were returned to production to take advantage of high crude oil prices.



Operating netback

Three months ended Nine months ended
USOGP September 30, September 30,
----------------------------------------------------------------------------
% %
($ per boe) 2007 2006 Change 2007 2006 Change
----------------------------------------------------------------------------

USOGP oil
equivalent
netback per
boe
Gross
production
revenue $ 66.24 $ 66.67 (1) $ 62.00 $ 64.26 (4)
Royalties (7.80) (6.57) 19 (6.96) (6.35) 10
Operating
costs (19.73) (17.94) 10 (20.74) (17.34) 20
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Field
operating
netback $ 38.71 $ 42.16 (8) $ 34.30 $ 40.57 (15)
Realized gain
(loss) on
financial
derivative
instruments (3.26) (3.08) 6 0.35 (2.09) -
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Operating
netback after
realized
financial
derivative
instruments $ 35.45 $ 39.08 (9) $ 34.65 $ 38.48 (10)
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Note: Per boe figures are calculated using sales volumes, which differ from
production volumes due to changes in inventory levels at the Florida
properties, acquired in the second quarter of 2007.


The third quarter 2007 field operating netback of $38.71 per boe was eight percent below the $42.16 per boe in the comparable quarter of 2006. The reduction reflects increased operating costs and royalties.



General and administrative

Three months ended Nine months ended
USOGP September 30, September 30,
----------------------------------------------------------------------------
($ 000s, except % %
per boe amounts) 2007 2006 Change 2007 2006 Change
----------------------------------------------------------------------------
Cash general
and
administrative $ 7,498 $ 5,730 31 $ 34,471 $ 19,680 75
Non-cash unit
based
compensation 2,305 777 197 104 4,676 (98)
----------------------------------------------------------------------------
$ 9,803 $ 6,507 51 $ 34,575 $ 24,356 42

Cash general
and
administrative
(per boe) $ 7.54 $ 8.05 (6) $ 13.46 $ 9.36 44
----------------------------------------------------------------------------
----------------------------------------------------------------------------


Cash general and administrative expenses in the third quarter 2007 of $7.5 million were 31 percent higher than the third quarter of 2006. The increase reflects additional staffing levels and regulatory costs associated with the MLP. On a boe basis however, costs were six percent lower in the third quarter of 2007, reflecting a 40 percent increase in volumes compared to the same period in 2006.

For the nine months ended September 30, 2007, cash general and administrative expenses were $34.5 million (2006 - $19.7 million). Year-to-date 2007 cash general and administrative expense includes $13.8 million or $5.40 per boe (2006 - $4.9 million or $2.33 per boe) related to payments associated with unit based compensation. The expense was accrued in 2006 as non-cash unit based compensation, consequently there is an offsetting reduction in non-cash unit based compensation in 2007, when the payments were made. Excluding these payments, cash general and administrative expenses were $20.7 million or $8.06 per boe for the nine months ended September 30, 2007 compared to $14.8 million or $7.03 per boe for the same period in 2006. The increase was due to increased costs associated with regulatory compliance as well as increased staffing levels upon establishment of the public MLP.

Non-cash unit based compensation expense was $2.3 million in the third quarter of 2007 compared to $0.8 million in the third quarter of 2006. The increase in incentive plan costs was primarily driven by an increase in the benchmark unit prices.

Non-cash unit based compensation for the nine months ended September 30, 2007 was $0.1 million (2006 - $4.7 million expense). Year-to-date 2007 cash payments related to unit based compensation were $13.8 million compared to $4.9 million in 2006. Payment of unit based compensation is recorded as cash general and administrative expense with an offsetting reduction in non-cash unit based compensation. Excluding this payment, non-cash unit based compensation was $13.9 million for the nine months ended September 30, 2007 (2006 - $9.6 million). The increase in expense in 2007 reflects higher staffing levels as well as strong MLP performance in the first three quarters of 2007.



Capital expenditures

Three months ended Nine months ended
USOGP September 30, September 30,
----------------------------------------------------------------------------
($ 000s) 2007 2006 2007 2006
----------------------------------------------------------------------------
Capital expenditures - by category
Geological, geophysical and land $ 390 $ - $ 1,671 $ -
Drilling and recompletions 10,195 5,569 30,296 24,147
Facilities and equipment 5,847 6,026 13,641 13,121
Other capital 1,098 1,887 5,249 2,755
----------------------------------------------------------------------------
Total additions $ 17,530 $ 13,482 $ 50,857 $ 40,023
----------------------------------------------------------------------------
----------------------------------------------------------------------------

Capital expenditures - by area
Los Angeles $ 4,714 $ 5,428 $ 8,802 $ 16,467
Santa Maria - Orcutt 8,167 2,364 23,974 8,703
Wyoming 1,374 4,017 9,715 12,354
Texas 244 - 315 -
Florida 2,381 - 3,493 -
Other capital 650 1,673 4,558 2,499
----------------------------------------------------------------------------
17,530 13,482 50,857 40,023
----------------------------------------------------------------------------
----------------------------------------------------------------------------

Property acquisitions, net $ 400 $ - $250,844 $ (2,008)
----------------------------------------------------------------------------
----------------------------------------------------------------------------


USOGP capital expenditures for the third quarter of 2007 totaled $17.5 million. $15.0 million of the capital expenditures were directed at drilling, optimization and facility upgrades at Santa Fe Springs, Wyoming, Florida and Orcutt. In addition, $1.9 million was directed at optimization projects at smaller fields and office equipment. A significant portion of optimization capital was directed at improvements to infrastructure aimed at reducing future operating expenses. A further $0.6 million was for the real estate development project at Orcutt.

In 2007, USOGP completed property acquisitions of $250.8 million. $115.6 million represents the Florida acquisition and $98.9 million was spent on an acquisition in California. An additional $36.3 million was directed at acquiring additional wells in Texas, Los Angeles and Wyoming.



Depletion, depreciation and accretion (DD&A)

Three months ended Nine months ended
USOGP September 30, September 30,
----------------------------------------------------------------------------
($ 000s, except % %
per boe amounts) 2007 2006 Change 2007 2006 Change
----------------------------------------------------------------------------

DD&A $ 11,004 $ 6,480 70 $ 28,052 $ 21,789 29
DD&A (per boe) $ 11.07 $ 9.10 22 $ 10.95 $ 10.36 6
----------------------------------------------------------------------------
----------------------------------------------------------------------------


The USOGP's DD&A rate is low due to the long-lived nature of the assets. On a per boe basis the DD&A rate was up $1.97 or 22 percent in the third quarter of 2007 when compared to the third quarter of 2006. The change reflects higher depletion costs related to the recent producing property acquisitions as well as year end 2006 DD&A rate adjustments.

Midstream business segment review

The Midstream business

The Midstream business unit extracts, processes, stores, transports and markets natural gas liquids (NGL) for Provident and offers these services to third party customers. The Provident Midstream segment contains three business lines:



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

Midstream business unit results can be summarized as follows:

Three months ended Nine months ended
September 30, September 30,
----------------------------------------------------------------------------
% %
($ 000s) 2007 2006 Change 2007 2006 Change
----------------------------------------------------------------------------

Empress East
Margin $ 42,176 $ 39,127 8 $ 106,455 $ 103,787 3
Redwater West
Margin 23,921 28,494 (16) 52,891 45,342 17
Commercial
Services
Margin 10,905 14,768 (26) 35,062 33,447 5
----------------------------------------------------------------------------
Gross
operating
margin 77,002 82,389 (7) 194,408 182,576 6
Cash general
and
administrative
expenses and
other (6,220) (5,459) 14 (22,313) (16,564) 35
Realized loss
on financial
derivative
instruments (23,357) (10,972) 113 (35,843) (20,803) 72
----------------------------------------------------------------------------
Midstream
EBITDA $ 47,425 $ 65,958 (28) $ 136,252 $ 145,209 (6)
----------------------------------------------------------------------------
----------------------------------------------------------------------------


Gross operating margin

a. 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. The higher the ratio, the better this business line will perform. There is also a differential between propane, butane and condensate prices and crude oil prices, which can change prices received and margins realized for Midstream products separate from frac spread ratio changes. In the third quarter of 2007, the margin for this business line was $42.2 million (2006 - $39.1 million). This increase is the result of slightly higher propane-plus prices and lower transportation related costs, partially offset by a four percent reduction in NGL sales volumes. The year-to-date margin was $106.5 million in 2007 compared to year-to-date 2006 of $103.8 million. The increase reflects slightly higher propane-plus prices and lower transportation related costs, partially offset by four percent lower NGL sales volumes. Also, the 2006 gross operating margin includes the impact of a $5.2 million repayment incurred under the fractionation spread support program.

b. 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. In the third quarter of 2007, the margin for this business line was $23.9 million (2006 - $28.5 million). The decrease in margin is primarily due to a five percent increase in the per-unit cost to acquire propane-plus product in the quarter. Year-to-date margin increased to $52.9 million from $45.3 million in 2006. The increase in margin was primarily due to a five percent increase in NGL sales volumes and lower product costs.

c. The Commercial Services business line:

The Commercial Services business line generates income from stable fee-for-service contracts to provide fractionation, storage, loading, and marketing services to upstream producers. Income from pipeline tariffs from Provident's ownership in NGL pipelines is also included in this business line. In the third quarter of 2007, the margin for this business line was $10.9 million (2006 - $14.8 million). The reduction in the margin is due to lower throughput in the period at the rail loading/off-loading facilities at Redwater. Year-to-date 2007, the commercial services margin was $35.0 million (2006 - $33.5 million). The improvement over 2006 results reflects the benefit of the June 2006 commissioning of the condensate rail off-loading terminal.

Operations - Midstream NGL sales volumes

Midstream sold 112,386 bpd in the third quarter of 2007, down two percent when compared with 114,839 bpd in the third quarter of 2006. Year-to-date Midstream sold 115,664 bpd in 2007, relatively unchanged compared to sales of 115,228 bpd in 2006.

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

Third quarter 2007 EBITDA of $47.4 million decreased $18.6 million or 28 percent from $66.0 million in the third quarter of 2006, primarily due to reduced participation in a rising market reflected in the increased realized loss on financial derivative instruments. Provident paid $23.4 million in the third quarter 2007 (2006 - $11.0 million) on realized financial derivative instruments related to Midstream margin stabilization activities. The increased cost in 2007 reflects lower natural gas prices in the period. Due to the seasonal nature of the Midstream business, the corresponding benefit of the lower natural gas prices is not fully reflected in quarterly gross operating margin. However, inventory levels of propane-plus products were increased during the quarter based on these lower natural gas prices. This increased inventory is expected to be sold in the upcoming winter months. Year-to-date EBITDA decreased to $136.3 million from $145.2 million in 2006 reflecting higher realized losses on financial derivative instruments and higher general and administrative expenses, partially offset by increased gross operating margins for all three business lines. Funds flow from operations for the third quarter of 2007 was $32.4 million, a decrease of $26.2 million or 45 percent below the $58.6 million for the third quarter 2006. Year-to-date funds flow from operations decreased to $101.3 million from $123.8 million in 2006. The decrease in funds flow from operations reflects the lower EBITDA combined with higher interest costs due to increased corporate long-term debt balances, and higher taxes.

Cash general and administrative expenses and other were $6.2 million for the third quarter 2007 (2006 - $5.5 million). Cash general and administrative costs in 2007 reflect additional provisions for short-term incentive compensation reflecting the performance of the Trust in relation to established benchmarks, as well as increases in ongoing regulatory compliance and reporting costs.

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

Fractionation spread support program

As part of the December 2005 Midstream NGL Acquisition, the vendor agreed to provide a near-term fractionation spread support program. The program provides Provident with up to $75 million of support in 2006 and up to October 31, 2007 if the fractionation spread ratio is below historic levels. This program is intended to ensure that Provident achieves the long-term average fractionation spread ratio that the NGL business has attained historically. In certain circumstances, the vendor will have the ability to recover the amounts provided under the support program until October 31, 2008, if the fractionation spread ratio exceeds historic levels. Provident's long-term risk management strategy is focused on locking in fractionation spread margins, with the objective of stabilizing funds flow from operations over the longer term.

There was no activity under this agreement in the first nine months of 2007 or the last three quarters of 2006. In the first quarter of 2006, there was a repayment of $5.2 million that was received in the fourth quarter of 2005.

Capital expenditures

Midstream capital expenditures for the third quarter of 2007 totaled $3.1 million, and $9.2 million year-to-date. In 2007, $3.9 million was spent on a new condensate offloading and terminalling facility, expansion to the recently completed truck loading facilities, and continued development of cavern storage. $2.1 million was spent on sustaining capital requirements and $3.2 million was spent on office furniture, equipment and other.



Distributions

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

Distribution Amount
Record Date Payment Date (Cdn$) (US$)(1)
----------------------------------------------------------------------------
2007
January 22, 2007 February 15, 2007 $ 0.12 0.10
February 28, 2007 March 15, 2007 0.12 0.10
March 22, 2007 April 13, 2007 0.12 0.11
April 24, 2007 May 15, 2007 0.12 0.11
May 18, 2007 June 15, 2007 0.12 0.11
June 22, 2007 July 13, 2007 0.12 0.11
July 23, 2007 August 15, 2007 0.12 0.11
August 22, 2007 September 14, 2007 0.12 0.12
September 24, 2007 October 15, 2007 0.12 0.12
----------------------------------------------------------------------------
2007 Cash Distributions paid
as declared $ 1.08 0.99
----------------------------------------------------------------------------
----------------------------------------------------------------------------
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 September 30, 2007
- Distributions paid as declared $ 12.03 8.95
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(1) Exchange rate based on the Bank of Canada noon rate on the payment date.
The increase in distributions in U.S. dollars is due to the increase in
the Canadian dollar relative to the U.S. dollar.


Foreign ownership

As at September 30, 2007, based on information received from the transfer agent and financial intermediaries, an estimated 82 percent 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

Financial instruments and comprehensive income

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

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

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

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

Long-term debt and deferred financing charges

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

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

Statement of comprehensive income

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

Inventory

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

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

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

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

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

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 nine months ended September 30, 2007 on both the Toronto Stock Exchange and the New York Stock Exchange:



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


Forward-looking statements

Certain statements included in this analysis constitute forward-looking statements under applicable securities legislation. These statements relate to future events or Provident's future performance. All statements other than statements of historical fact are forward-looking statements. In some cases, forward-looking statements can be identified by terminology such as "may", "will", "should", "expect", "plan", "anticipate", "believe", "estimate", "predict", "potential", "continue", or the negative of these terms or other comparable terminology. Forward-looking statements or information in this analysis include, but are not limited to, business strategy and objectives, reserve quantities and the discounted present value of future net funds flow from operations from such reserves, net revenue, future production levels, capital expenditures, exploration plans, development plans, acquisition and disposition plans and the timing thereof, operating and other costs, royalty rates, budgeted levels of cash distributions and the performance associated with Provident's natural gas midstream, NGL processing and marketing business. These statements are only predictions. Actual events or results may differ materially. In addition, this analysis may contain forward-looking statements attributed to third party industry sources. Undue reliance should not be placed on these forward-looking statements, as there can be no assurance that the plans, intentions or expectations upon which they are based will occur. By its nature, forward-looking information involves numerous assumptions, known and unknown risks and uncertainties, both general and specific, that contribute to the possibility that the predictions, forecasts, projections and other forward-looking statements will not occur. In addition to other assumptions identified in this analysis, assumptions in respect of forward-looking statements have been made regarding, among other things:

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

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

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

- the emergence of accretive growth opportunities;

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

- the impact of Canadian governmental regulation on Provident, including the effect of new legislation taxing trust income;

- 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 funds flow from operations after hedging;

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

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

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

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

- currency, exchange and interest rates;

- the performance characteristics of Provident's NGL services, processing and marketing business;

- the growth opportunities associated with the NGL services, processing and marketing business; and

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

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

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

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

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

- uncertainties associated with estimating reserves;

- royalties payable in respect of oil and gas production;

- interest payable on notes issued in connection with acquisitions;

- income tax legislation relating to income trusts, including the effect of 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; and

- third party performance of obligations under contractual arrangements.

Statements relating to "reserves" or "resources" are deemed to be forward-looking statements, as they involve the implied assessment, based on certain estimates and assumptions, that the resources and reserves described can be profitably produced in the future. Readers are cautioned that the foregoing list of factors is not exhaustive. The forward-looking statements contained in this analysis are expressly qualified by this cautionary statement. Subject to Provident's obligations under applicable securities laws, Provident is not under any duty to update any of the forward-looking statements after the date of this analysis to conform such statements to actual results or to changes in Provident's expectations.



Segmented information by quarter
----------------------------------------------------------------------------
($000s except for per unit
and operating amounts) 2007
----------------------------------------------------------------------------
First Second Third Year-to-
Quarter(1) Quarter(1) Quarter Date
----------------------------------------------------------------------------
Financial - consolidated
Revenue $ 587,675 $ 504,468 $ 533,249 $ 1,625,392
Funds flow from
operations $ 87,040 $ 98,503 $ 105,149 $ 290,692
Net income (loss) $ 43,093 $ (46,199) $ (35,005) $ (38,111)
Net income (loss) per
unit - basic and diluted $ 0.20 $ (0.21) $ (0.14) $ (0.17)
Unitholder distributions $ 76,271 $ 80,236 $ 87,782 $ 244,289
Distributions per unit $ 0.36 $ 0.36 $ 0.36 $ 1.08
----------------------------------------------------------------------------

Oil and gas production
Cash revenue $ 125,777 $ 139,453 $ 155,541 $ 420,771
Earnings before interest,
DD&A, taxes and other
non-cash items $ 54,736 $ 75,783 $ 82,523 $ 213,042
Funds flow from operations $ 47,636 $ 68,934 $ 72,799 $ 189,369
Net (loss) income $ (8,745) $ 95,992 $ (26,375) $ 60,872
----------------------------------------------------------------------------

Midstream services and
marketing
Cash revenue $ 453,272 $ 397,713 $ 433,950 $ 1,284,935
Earnings before interest,
DD&A, taxes and other
non-cash items $ 52,853 $ 35,974 $ 47,425 $ 136,252
Funds flow from operations $ 39,404 $ 29,569 $ 32,350 $ 101,323
Net income (loss) $ 51,838 $ (142,191) $ (8,630) $ (98,983)
----------------------------------------------------------------------------

Operating
Oil and gas production
Light/medium oil (bpd) 14,071 15,557 19,289 16,323
Heavy oil (bpd) 1,669 1,918 2,324 1,973
Natural gas liquids (bpd) 1,444 1,344 1,281 1,356
Natural gas (mcfd) 91,432 96,449 95,588 94,505
Oil equivalent (boed) 32,423 34,893 38,825 35,403
----------------------------------------------------------------------------

Average selling price net
of transportation expense
(Cdn$)
Light/medium oil per bbl
(before realized
financial derivative
instruments) $ 57.21 $ 59.44 $ 64.59 $ 60.89
Light/medium oil per bbl
(including realized
financial derivative
instruments) $ 59.93 $ 59.39 $ 61.37 $ 60.35
Heavy oil per bbl
(before realized
financial derivative
instruments) $ 34.69 $ 42.32 $ 45.34 $ 41.39
Heavy oil per bbl
(including realized
financial derivative
instruments) $ 34.69 $ 42.32 $ 45.34 $ 41.39
Natural gas liquids per
barrel $ 48.86 $ 52.56 $ 55.22 $ 52.11
Natural gas per mcf
(before realized
financial derivative
instruments) $ 7.48 $ 7.25 $ 4.95 $ 6.54
Natural gas per mcf
(including realized
financial derivative
instruments) $ 7.37 $ 7.18 $ 5.62 $ 6.71
----------------------------------------------------------------------------

Midstream
Midstream NGL sales
volumes (bpd) 125,033 109,713 112,386 115,664
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(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 $ 553,706 $ 424,439 $ 661,022 $ 548,086 $ 2,187,253
Funds flow from
operations $ 78,906 $ 110,990 $ 120,089 $ 122,679 $ 432,664
Net income (loss) $ 24,200 $ 21,371 $ 120,850 $ (25,501) $ 140,920
Net income (loss)
per unit - basic $ 0.13 $ 0.11 $ 0.61 $ (0.12) $ 0.72
Net income (loss)
per unit - diluted $ 0.13 $ 0.11 $ 0.58 $ (0.12) $ 0.72
Unitholder
distributions $ 68,350 $ 68,572 $ 70,970 $ 75,573 $ 283,465
Distributions per
unit $ 0.36 $ 0.36 $ 0.36 $ 0.36 $ 1.44
----------------------------------------------------------------------------

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

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

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

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

Midstream
Midstream NGL sales
volumes (bpd) 130,735 100,284 114,839 112,853 114,629
----------------------------------------------------------------------------
----------------------------------------------------------------------------


Segmented information by quarter
----------------------------------------------------------------------------
($000s except for per
unit and operating
amounts) 2005
----------------------------------------------------------------------------
First Second Third Fourth Annual
Quarter Quarter Quarter Quarter Total
----------------------------------------------------------------------------
Financial -
consolidated
Revenue $ 322,023 $ 300,504 $ 295,060 $ 442,687 $ 1,360,274
Funds flow from
operations $ 64,137 $ 64,435 $ 86,318 $ 96,298 $ 311,188
Net income (loss) $ (2,783) $ 26,822 $ 18,386 $ 54,501 $ 96,926
Net income (loss)
per unit - basic
and diluted $ (0.02) $ 0.17 $ 0.11 $ 0.32 $ 0.61
Unitholder
distributions $ 51,734 $ 57,001 $ 59,333 $ 62,646 $ 230,714
Distributions per
unit $ 0.36 $ 0.36 $ 0.36 $ 0.36 $ 1.44
----------------------------------------------------------------------------
----------------------------------------------------------------------------

Oil and gas
production
Cash revenue $ 100,447 $ 104,478 $ 124,073 $ 117,710 $ 446,708
Earnings before
interest, DD&A,
taxes and other
non-cash items $ 59,262 $ 63,584 $ 81,670 $ 73,976 $ 278,492
Funds flow from
operations $ 48,937 $ 53,868 $ 74,139 $ 68,006 $ 244,950
Net income (loss) $ (15,046) $ 14,681 $ 10,702 $ 30,437 $ 40,774
----------------------------------------------------------------------------

Midstream services
and marketing
Cash revenue $ 245,338 $ 186,635 $ 180,875 $ 293,034 $ 905,882
Earnings before
interest, DD&A,
taxes and other
non-cash items $ 16,380 $ 11,765 $ 12,978 $ 29,566 $ 70,689
Funds flow from
operations $ 15,200 $ 10,567 $ 12,179 $ 28,292 $ 66,238
Net income $ 12,263 $ 12,141 $ 7,684 $ 24,064 $ 56,152
----------------------------------------------------------------------------

Operating
Oil and gas
production
Light/medium oil
(bpd) 14,388 15,891 15,583 14,051 14,979
Heavy oil (bpd) 5,547 4,644 4,075 3,195 4,358
Natural gas liquids
(bpd) 1,756 1,454 1,523 1,653 1,596
Natural gas (mcfd) 80,466 79,126 75,523 73,363 77,095
Oil equivalent
(boed) 35,102 35,177 33,768 31,126 33,782
----------------------------------------------------------------------------

Average selling
price net of
transportation
expense (Cdn$)
Light/medium oil
per bbl
(before realized
financial
derivative
instruments) $ 49.32 $ 51.20 $ 62.95 $ 55.31 $ 54.69
Light/medium oil
per bbl
(including realized
financial
derivative
instruments) $ 40.93 $ 42.18 $ 49.82 $ 42.52 $ 43.90
Heavy oil per bbl
(before realized
financial
derivative
instruments) $ 25.85 $ 26.03 $ 46.74 $ 28.62 $ 31.33
Heavy oil per bbl
(including realized
financial
derivative
instruments) $ 25.78 $ 26.03 $ 46.74 $ 28.62 $ 31.31
Natural gas liquids
per barrel $ 45.30 $ 47.75 $ 54.27 $ 49.44 $ 49.09
Natural gas per mcf
(before realized
financial
derivative
instruments) $ 6.76 $ 7.29 $ 8.43 $ 11.44 $ 8.43
Natural gas per mcf
(including realized
financial
derivative
instruments) $ 6.74 $ 7.13 $ 8.03 $ 11.22 $ 8.23
----------------------------------------------------------------------------
----------------------------------------------------------------------------



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


As at As at
September 30, December 31,
2007 2006
--------------- --------------
Assets
Current assets
Cash and cash equivalents $ 10,061 $ 10,302
Accounts receivable 284,857 270,135
Petroleum product inventory 136,732 85,868
Prepaid expenses and other current assets
(note 11) 47,724 16,381
Financial derivative instruments 9,514 12,909
----------------------------------------------------------------------------
488,888 395,595

Investments 8,235 4,320
Deferred financing charges - 12,351
Long-term financial derivative instruments 138 171
Property, plant and equipment 2,957,782 2,333,537
Intangible assets 179,837 193,592
Goodwill 518,023 431,353
----------------------------------------------------------------------------
$ 4,152,903 $ 3,370,919
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Liabilities
Current liabilities
Accounts payable and accrued liabilities $ 385,940 $ 295,003
Cash distributions payable 24,081 21,506
Distributions payable to non-controlling
interests - 677
Financial derivative instruments 75,316 22,602
----------------------------------------------------------------------------
485,337 339,788

Long-term debt - revolving term credit
facilities (note 5) 942,495 702,993
Long-term debt - convertible debentures
(note 5) 274,641 285,792
Asset retirement obligation (note 6) 55,052 49,614
Long-term financial derivative instruments 68,313 43,336
Other long-term liabilities (note 9) 23,292 16,305
Future income taxes 486,510 309,006
Non-controlling interests (note 7)
USOGP operations 182,804 81,111

Unitholders' equity
Unitholders' contributions (note 8) 2,656,988 2,254,048
Convertible debentures equity component 18,227 18,522
Contributed surplus (note 9) 892 1,315
Accumulated other comprehensive (loss)
income (70,631) (42,294)
Accumulated income 200,097 238,208
Accumulated cash distributions (1,171,114) (926,825)
----------------------------------------------------------------------------
1,634,459 1,542,974
----------------------------------------------------------------------------
$ 4,152,903 $ 3,370,919
----------------------------------------------------------------------------
----------------------------------------------------------------------------


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


Three months ended Nine months ended
September 30, September 30,
---------------------------------------------
2007 2006 2007 2006
---------------------------------------------
Revenue
Revenue $ 612,682 $ 587,497 $ 1,739,441 $1,682,166
Realized loss on financial
derivative instruments (23,191) (11,212) (33,735) (23,978)
Unrealized (loss) gain on
financial derivative
instruments (56,242) 84,737 (80,314) (19,021)
----------------------------------------------------------------------------
533,249 661,022 1,625,392 1,639,167

Expenses
Cost of goods sold 379,400 384,306 1,116,056 1,111,151
Production, operating and
maintenance 54,003 37,279 144,864 125,322
Transportation 7,915 3,042 19,378 12,885
Depletion, depreciation
and accretion 94,510 58,642 247,439 164,655
General and administrative
(note 9) 31,020 20,695 94,110 64,518
Interest on bank debt 13,962 9,334 33,604 23,504
Interest and accretion on
convertible debentures 6,283 5,972 19,092 18,119
Amortization of deferred
financing charges - 963 - 2,800
Foreign exchange gain and
other (889) (682) (248) (1,049)
Dilution gain (note 7) - - (98,592) -
----------------------------------------------------------------------------
586,204 519,551 1,575,703 1,521,905
----------------------------------------------------------------------------
(Loss) income before taxes
and non-controlling
interests (52,955) 141,471 49,689 117,262
----------------------------------------------------------------------------
Capital tax expense 2,364 259 3,252 862
Current and withholding tax
expense (recovery) 3,493 (1,328) 6,623 4,396
Future income tax
(recovery) expense (note 10) (19,302) 19,406 88,080 (55,569)
----------------------------------------------------------------------------
(13,445) 18,337 97,955 (50,311)
Net (loss) income before
non-controlling interests (39,510) 123,134 (48,266) 167,573
----------------------------------------------------------------------------
Non-controlling interests
USOGP operations (4,505) 1,929 (10,155) 547
Exchangeable shares - 355 - 605
----------------------------------------------------------------------------
Net (loss) income (35,005) 120,850 (38,111) 166,421
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Accumulated income,
beginning of period $ 235,102 $ 142,859 $ 238,208 $ 97,288
----------------------------------------------------------------------------
Accumulated income, end of
period $ 200,097 $ 263,709 $ 200,097 $ 263,709
----------------------------------------------------------------------------
Net (loss) income per unit
- basic $ (0.14) $ 0.61 $ (0.17) $ 0.87
----------------------------------------------------------------------------
Net (loss) income per unit
- diluted $ (0.14) $ 0.58 $ (0.17) $ 0.86
----------------------------------------------------------------------------


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


Three months ended Nine months ended
September 30, September 30,
--------------------------------------------
2007 2006 2007 2006
--------------------------------------------
Cash provided by operating
activities
Net (loss) income for the
period $ (35,005) $ 120,850 $ (38,111) $ 166,421
Add (deduct) non-cash items:
Depletion, depreciation and
accretion 94,510 58,642 247,439 164,655
Non-cash interest expense
and other 1,303 1,581 3,969 4,696
Non-cash unit based
compensation (note 9) 10,902 2,925 15,806 10,272
Unrealized loss (gain) on
financial derivative
instruments 56,242 (84,737) 80,314 19,021
Unrealized foreign exchange
loss (gain) and other 1,004 (862) 1,942 (663)
Future income tax (recovery)
expense (19,302) 19,406 88,080 (55,569)
Dilution gain (note 7) - - (98,592) -
Net (loss) income
attributable to
non-controlling interests (4,505) 2,284 (10,155) 1,152
----------------------------------------------------------------------------
Funds flow from operations 105,149 120,089 290,692 309,985
----------------------------------------------------------------------------
Site restoration
expenditures (590) (1,257) (2,340) (3,408)
Change in non-cash operating
working capital (13,904) (48,904) 38,773 (55,117)
----------------------------------------------------------------------------
90,655 69,928 327,125 251,460

Cash (used for) provided by
financing activities
Increase in long-term debt 71,067 290,225 200,159 288,395
Distributions to unitholders (87,782) (70,970) (244,289) (207,892)
Distributions to
non-controlling interests (6,583) (698) (13,722) (1,808)
Issue of trust units, net of
issue costs 15,248 221,849 396,475 242,418
Contributions by
non-controlling interests 1,153 - 241,281 2,675
Change in non-cash financing
working capital 3,060 (127) 7,236 (644)
----------------------------------------------------------------------------
(3,837) 440,279 587,140 323,144
----------------------------------------------------------------------------
Cash used for investing
activities
Capital expenditures (54,317) (38,254) (153,757) (129,522)
Capitol Energy acquisition
(note 4) - - (467,850) -
Acquisition of Midstream NGL
business - - - (2,300)
Oil and gas property
acquisitions, net (2,260) (472,731) (262,413) (472,947)
Deposit on acquisition
(note 11) (34,871) - (34,871) -
Increase in investments (5,450) - (5,450) -
Proceeds on sale of assets - - 7,624 11,517
Reclamation fund
contributions (590) (636) (2,340) (1,910)
Reclamation fund withdrawals 590 1,257 2,340 3,408
Change in non-cash investing
working capital 11,122 3,544 2,211 (8,463)
----------------------------------------------------------------------------
(85,776) (506,820) (914,506) (600,217)
----------------------------------------------------------------------------

Increase (decrease) in cash
and cash equivalents 1,042 3,387 (241) (25,613)
Cash and cash equivalents
beginning of period 9,019 3,113 10,302 32,113
----------------------------------------------------------------------------
Cash and cash equivalents end
of period $ 10,061 $ 6,500 $ 10,061 $ 6,500
----------------------------------------------------------------------------
----------------------------------------------------------------------------

Supplemental disclosure of
cash flow information
Cash interest paid including
debenture interest $ 17,691 $ 9,045 $ 46,547 $ 39,324
Cash taxes paid $ 1,740 $ 1,736 $ 10,539 $ 9,082
----------------------------------------------------------------------------
----------------------------------------------------------------------------


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


Three months ended Nine months ended
September 30, September 30,
---------------------------------------------
2007 2006 2007 2006
---------------------------------------------
Net (loss) income $ (35,005) $ 120,850 $ (38,111) $ 166,421
----------------------------------------------------------------------------
Other comprehensive (loss)
income, net of taxes
Foreign currency translation
adjustments (11,899) 331 (27,023) (10,397)
Unrealized loss on
available-for-sale investments
(net of taxes of $29 and $221,
respectively) (33) - (1,314) -
----------------------------------------------------------------------------
(11,932) 331 (28,337) (10,397)
Comprehensive (loss) income $ (46,937) $ 121,181 $ (66,448) $ 156,024
----------------------------------------------------------------------------
----------------------------------------------------------------------------

Accumulated other comprehensive
(loss) income, beginning of
period (58,699) (52,513) (42,294) (41,785)
Other comprehensive (loss)
income (11,932) 331 (28,337) (10,397)
----------------------------------------------------------------------------
Accumulated other comprehensive
(loss) income, end of period $ (70,631) $ (52,182) $(70,631) $ (52,182)
Accumulated income, end of
period 200,097 263,709 200,097 263,709
----------------------------------------------------------------------------
Total accumulated income and
accumulated other comprehensive
income, end of period $ 129,466 $ 211,527 $ 129,466 $ 211,527
----------------------------------------------------------------------------
----------------------------------------------------------------------------


NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
(Tabular amounts in Cdn$000's, except unit and per unit amounts)
(unaudited)


September 30, 2007

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, 2006.

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 Financial Statements of the Trust for the year ended December 31, 2006 and are consistent with policies adopted in the third quarter of 2006, except as described in note 2. Certain comparative numbers have been reclassified to conform with the current period's presentation.

2. Changes in accounting policies and practices

(i) Financial instruments

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

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

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

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

Long-term debt and deferred financing charges

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

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

Comprehensive income

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

(ii) Inventory

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

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

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

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

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

3. Restatement of 2007 interim consolidated financial statements

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 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 first and second quarters of 2007 is summarized below. There is no effect on 2006 or prior periods.



Effect on Effect on Effect on
the three the three the six
months ended months ended months ended
March 31, June 30, June 30,
(000's except per unit amounts) 2007 2007 2007
----------------------------------------------------------------------------

Increase in accounts receivable $ 3,138 $ 888 $ 4,026
(Decrease) in petroleum product
inventory (13,226) (8,095) (21,321)
Decrease in future income tax
liability 2,875 2,054 4,929
----------------------------------------------------------------------------
(Decrease) in unitholders' equity $ (7,213) $ (5,153) $ (12,366)
----------------------------------------------------------------------------

(Increase) in cost of goods sold $ (10,088) $ (7,207) $ (17,295)
Decrease in future income tax expense 2,875 2,054 4,929
----------------------------------------------------------------------------
(Decrease) in net income $ (7,213) $ (5,153) $ (12,366)
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(Decrease) in net income per unit -
basic and diluted $ (0.04) $ (0.02) $ (0.05)
----------------------------------------------------------------------------
----------------------------------------------------------------------------


4. Acquisitions

(i) Acquisition of Capitol

On June 19, 2007, the Trust acquired Capitol Energy Resources Ltd. ("Capitol") for cash consideration of $467.9 million. Capitol was a public oil and gas exploration and production company active in the Western Canadian sedimentary basin. The transaction has been accounted for using the purchase method with the allocation of the purchase price as follows:



Net assets acquired and liabilities assumed
Property, plant and equipment $ 522,707
Goodwill 86,670
Working capital, net 17,033
Bank debt (53,100)
Financial derivative instruments (621)
Asset retirement obligation (1,752)
Future income taxes (103,087)
----------------------------------------------------------------------------
$ 467,850
----------------------------------------------------------------------------
Consideration
Acquisition costs $ 1,470
Cash 466,380
----------------------------------------------------------------------------
$ 467,850
----------------------------------------------------------------------------
----------------------------------------------------------------------------


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

(ii) MLP acquisitions

In May 2007, BreitBurn Energy Partners L.P. (the "MLP") completed two oil and gas property acquisitions, one in Florida for cash consideration of USD $107.7 million and one in California for cash consideration of USD $92.4 million. The transactions were accounted for as asset purchases with the allocation of cost as follows (in Canadian dollars):



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

The acquisitions were financed by the issue of units by the MLP to
institutional investors (see note 7).

5. Long-term debt

as at as at
September 30, 2007 December 31, 2006
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Revolving term credit facilities $ 942,495 $ 702,993
Convertible debentures 274,641 285,792
----------------------------------------------------------------------------
$ 1,217,136 $ 988,785
----------------------------------------------------------------------------
----------------------------------------------------------------------------


(i) Revolving term credit facility

At September 30, 2007 the Trust had $1,125 million and USD $212.7 million term credit facilities (December 31, 2006 - $925 million and USD $158 million). At September 30, 2007, $883.3 million was drawn on the Canadian facility and $61.8 million was drawn on the USD facility. Included in the carrying value at September 30, 2007 were financing costs of $2.6 million.

At September 30, 2007 the Trust had letters of credit guaranteeing Provident's performance under certain commercial and other contracts that totaled $32.9 million. The guarantees totaled $31.9 million at December 31, 2006.

(ii) Convertible debentures

The Trust may elect to satisfy interest and principal obligations by the issue of trust units. For the three and nine month periods ended September 30, 2007, $5.2 million and $5.8 million, respectively, of the face value of debentures were converted to trust units at the election of debenture holders (2006 - $9.0 million and $12.2 million, respectively). Included in the carrying value at September 30, 2007 were financing costs of $7.6 million. The following table details each convertible debenture:



as at as at
Convertible Debentures September 30, 2007 December 31, 2006
----------------------------------------------------------------------------
Conversion
($ 000s except Price
conversion Carrying Face Carrying Face Maturity per
pricing) Value(1) Value Value(1) Value Date unit(2)
----------------------------------------------------------------------------
6.5% Convertible April 30,
Debentures $ 139,871 $149,980 $ 142,860 $150,000 2011 14.75

6.5% Convertible Aug. 31,
Debentures 91,109 99,024 93,134 99,024 2012 13.75

8.0% Convertible July 31,
Debentures 24,369 25,109 24,402 25,114 2009 12.00

8.75% Convertible Dec. 31,
Debentures 19,292 20,206 25,396 25,972 2008 11.05
----------------------------------------------------------------------------
$ 274,641 $294,319 $ 285,792 $300,110
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(1) Excluding equity component of convertible debentures
(2) The debentures may be converted into trust units at the option of the
holder of the debenture at the conversion price per unit


6. 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 months ended Nine months ended
September 30, September 30,
----------------------------------------------------------------------------
----------------------------------------------------------------------------
($000s) 2007 2006 2007 2006
----------------------------------------------------------------------------
Carrying amount, beginning
of period $ 55,720 $ 40,295 $ 49,614 $ 41,133
Acquisitions - 1,903 6,460 1,903
Change in estimate - - - 157
Increase in liabilities
incurred during the period 225 182 1,315 886
Settlement of liabilities
during the period (590) (1,257) (2,340) (3,408)
Decrease in liabilities
due to disposition (205) - (654) (773)
Accretion of liability 1,213 895 3,465 2,580
Foreign currency translation
adjustments (1,311) 15 (2,808) (445)
----------------------------------------------------------------------------
Carrying amount, end
of period $ 55,052 $ 42,033 $ 55,052 $ 42,033
----------------------------------------------------------------------------
----------------------------------------------------------------------------


7. Non-controlling interests - USOGP

Three months ended Nine months ended
September 30, September 30,
----------------------------------------------------------------------------
----------------------------------------------------------------------------
2007 2006 2007 2006
----------------------------------------------------------------------------
Non-controlling interests,
beginning of period $ 205,365 $ 12,068 $ 81,111 $ 11,885
Net (loss) income
attributable to
non-controlling interests (4,505) 1,929 (10,155) 547
Distributions to
non-controlling interests (6,583) (698) (13,722) (1,808)
Investments by
non-controlling interests 1,240 - 144,372 2,675
Foreign currency translation
adjustment (12,713) - (18,802) -
----------------------------------------------------------------------------
Non-controlling interests,
end of period $ 182,804 $ 13,299 $ 182,804 $ 13,299
----------------------------------------------------------------------------
Accumulated (loss) income
attributable to
non-controlling interests $ (4,641) $ 3,066 $ (4,641) $ 3,066
----------------------------------------------------------------------------
----------------------------------------------------------------------------


A non-controlling interest arose from the Trust's June 15, 2004 acquisition of 92 percent of BreitBurn Energy Company L.P. (BreitBurn) of Los Angeles, California. Additional investments since June 2004 by the Trust in BreitBurn have reduced this non-controlling interest percentage at September 30, 2007 to approximately 4.1 percent (December 31, 2006 - 4.4 percent).

In the second quarter of 2006, a USOGP subsidiary began a land development project with a partner. The subsidiary has a 20 percent interest, with the partner holding 80 percent. Because the subsidiary stands to receive a majority share of the future proceeds, the Trust is consolidating the results in its financial statements, with the partner's interest recorded as non-controlling interest. Contributions by the non-controlling interest were $1.2 million in the quarter ended September 30, 2007 (2006 - nil) and were $3.8 million year-to-date (2006 - $2.7 million).

In the fourth quarter of 2006, the Trust's subsidiary, BreitBurn Energy Partners, L.P. (the "MLP") completed its initial public offering. BreitBurn transferred oil and gas properties comprising approximately half of its proved reserves and two thirds of its daily production to the MLP. The offering of 6.9 million common units at U.S. $18.50 per unit initially resulted in approximately 34 percent of the MLP held by partners not related to Provident. During the second quarter of 2007, the MLP issued 7.0 million common units to third parties for proceeds of $237.5 million. As a result of this transaction, Provident's interest in the MLP decreased from approximately 66 percent to approximately 50 percent, resulting in a dilution gain of $98.6 million recorded in the consolidated statement of operations. The Trust, through its 95.6 percent general partnership interest, continues to control and consolidate the MLP.



8. Unitholders' contributions

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

Nine months ended September 30,
----------------------------------------------------------------------------
2007 2006
----------------------------------------------------------------------------
Trust Units Number of Amount Number of Amount
units (000s) units (000s)
----------------------------------------------------------------------------
Balance at beginning
of period 211,228,407 $ 2,254,048 188,772,788 $ 1,971,707
Issued for cash 29,313,727 373,750 16,325,000 224,142
Exchangeable share
conversions - - 109,934 1,417
Issued pursuant to unit
option plan 694,017 7,036 518,393 5,016
Issued pursuant to the
distribution reinvestment
plan 2,564,432 30,120 1,762,171 21,735
To be issued pursuant to
the distribution
reinvestment plan 423,697 5,237 160,000 3,759
Debenture conversions 523,571 5,985 1,061,352 12,493
Unit issue costs - (19,188) - (11,942)
----------------------------------------------------------------------------
Balance at end of period 244,747,851 $ 2,656,988 208,709,638 $ 2,228,327
----------------------------------------------------------------------------


The per trust unit amounts for the quarter ended September 30, 2007 were calculated based on the weighted average number of units outstanding of 243,600,188 (2006 - 197,155,970). The diluted per trust unit amounts for 2007 are calculated including an additional 175,068 trust units (2006 - 23,205,662) for the dilutive effect of the unit option plan and convertible debentures.

The per trust unit amounts for the nine months ended September 30, 2007 were calculated based on the weighted average number of units outstanding of 224,173,699 (2006 - 192,179,627). The diluted per trust unit amounts for 2007 are calculated including an additional 175,068 trust units (2006 - 7,587,609) for the dilutive effect of the unit option plan and convertible debentures.

9. Unit based compensation

(i) Restricted/Performance units

As of September 30, 2007 there were 1,362,883 RTUs and 4,735,215 PTUs outstanding (December 31, 2006 - 571,423 RTUs and 1,704,234 PTUs). The fair value estimate associated with the RTUs and PTUs is expensed in the statement of operations over the vesting period. At September 30, 2007, $15.9 million (December 31, 2006 - $2.3 million) is included in accounts payable and accrued liabilities for this plan and $19.3 million (December 31, 2006 - $13.3 million) is included in other long-term liabilities. The following table reconciles the expense recorded for RTUs and PTUs.



Three months ended Nine months ended
September 30, September 30,
----------------------------------------------------------------------------
----------------------------------------------------------------------------
2007 2006 2007 2006
----------------------------------------------------------------------------
Cash general and
administrative $ 355 $ 347 $ 2,328 $ 1,021
Non-cash unit based
compensation (included
in general and administrative) 9,409 2,101 18,767 5,922
Production, operating and
maintenance expense 417 - 1,223 -
----------------------------------------------------------------------------
$ 10,181 $ 2,448 $ 22,318 $ 6,943
----------------------------------------------------------------------------


(ii) Unit option plan

Nine months ended September 30,
----------------------------------------------------------------------------
2007 2006
----------------------------------------------------------------------------
Weighted Weighted
Number of Average Number of Average
Options Exercise Price Options Exercise Price
----------------------------------------------------------------------------
Outstanding, beginning
of period 2,114,808 $ 11.09 3,205,625 $ 11.11
Exercised (694,017) 11.15 (518,393) 10.93
Forfeited (10,288) 11.29 (14,332) 10.59
----------------------------------------------------------------------------
Outstanding, end of
period 1,410,503 11.05 2,672,900 11.14
----------------------------------------------------------------------------
Exercisable, end of
period 1,410,503 $ 11.05 2,045,694 $ 11.18
----------------------------------------------------------------------------


At September 30, 2007, the Trust had 1,410,503 options outstanding (September 30, 2006 - 2,672,900) with strike prices ranging from $10.49 to $12.14 per unit (September 30, 2006 - $10.49 and $12.14 per unit). The weighted average remaining contractual life of the options was 1.03 years (September 30, 2006 - 1.79 years) and the weighted average exercise price was $11.05 per unit (September 30, 2006 - $11.14 per unit) excluding average potential reductions to the strike prices of $1.68 per unit (September 30, 2006 - $1.49 per unit).



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

Three months ended Nine months ended
September 30, September 30,
----------------------------------------------------------------------------
----------------------------------------------------------------------------
2007 2006 2007 2006
----------------------------------------------------------------------------
Contributed surplus, beginning
of the period $ 935 $ 1,692 $ 1,315 $ 1,675
Non-cash unit based
compensation (included in
general and administrative) 2 49 57 271
Benefit on options exercised
charged to unitholders' equity (45) (87) (480) (292)
----------------------------------------------------------------------------
Contributed surplus,
end of period $ 892 $ 1,654 $ 892 $ 1,654
----------------------------------------------------------------------------
----------------------------------------------------------------------------


(iii) Unit appreciation rights (UARs)

At September 30, 2007, $0.8 million (December 31, 2006 - $2.5 million) is included in accounts payable and accrued liabilities for this plan and nil (December 31, 2006 - $0.1 million) is included in other long-term liabilities. The following table reconciles the expense recorded for UARs.



Three months ended Nine months ended
September 30, September 30,
----------------------------------------------------------------------------
----------------------------------------------------------------------------
2007 2006 2007 2006
----------------------------------------------------------------------------
Cash general and
administrative $ 382 $ 722 $ 2,072 $ 781
Non-cash unit based
compensation (included in
general and administrative) (104) (1,614) (1,578) (691)
----------------------------------------------------------------------------
$ 278 $ (892) $ 494 $ 90
----------------------------------------------------------------------------
----------------------------------------------------------------------------

The following table summarizes the information about UARs:

Nine months ended September 30,
----------------------------------------------------------------------------
2007 2006
----------------------------------------------------------------------------
Weighted Weighted
Number Average Number Average
of Unit Exercise of Unit Exercise
Appreciation Price Appreciation Price
Rights (U.S.$) Rights (U.S.$)
----------------------------------------------------------------------------
Outstanding, beginning
of period 472,521 $ 8.41 768,693 $ 8.34
Exercised (291,790) 9.25 (252,053) 8.19
Forfeited - - - -
----------------------------------------------------------------------------
Outstanding, end
of period (1) 180,731 $ 9.65 516,640 $ 8.41
----------------------------------------------------------------------------
Exerciseable, end
of period 124,068 $ 9.58 88,527 $ 10.74
----------------------------------------------------------------------------
Weighted average
remaining contract
life (years) 1.18 1.83
Average potential
reductions to exercise
price $ 0.40 $ 1.12
----------------------------------------------------------------------------
(1) A cash payment of $0.9 (million in the first quarter of 2007 resulted
in an adjustment to the weighted average exercise price.)


(iv) Other unit based compensation

At September 30, 2007 there were 2,755,566 notional units outstanding under the key employee plan (December 31, 2006 - 2,755,566) which vest one third three years after grant date, one third four years after grant date and one third five years after grant date. There were 6,234,932 notional units outstanding under the phantom unit plan (December 31, 2006 - 12,984,001) of which all notional units vest immediately and are payable 90 days from the fiscal year-end. At September 30, 2007, $9.0 million (December 31, 2006 - $13.4 million) is included in accounts payable and accrued liabilities for these plans, and $4.0 million (December 31, 2006 - $2.9 million) is included in other long-term liabilities.



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

Three months ended Nine months ended
September 30, September 30,
----------------------------------------------------------------------------
----------------------------------------------------------------------------
2007 2006 2007 2006
----------------------------------------------------------------------------
Cash general and
administrative $ - $ - $ 11,189 $ 3,807
Non-cash unit based
compensation (included
in general and
administrative) 1,595 2,389 (1,440) 4,770
----------------------------------------------------------------------------
$ 1,595 $ 2,389 $ 9,749 $ 8,577
----------------------------------------------------------------------------
----------------------------------------------------------------------------


10. Future income taxes

In 2007, future income tax expense includes $105.7 million relating to the enactment of Bill C-52, Budget Implementation Act 2007 by the Canadian government. This bill contains legislation to tax publicly traded trusts including the Trust. As a result of this legislation, the Trust is now required to record the future tax effect of the temporary differences on its flow through entities that are expected to reverse subsequent to 2010. The Trust has recorded the future income tax provision relating to this legislation as a rate change resulting in incremental future income tax expense of $105.7 million.

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

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

11. Subsequent events

U.S. acquisition closed

On November 1, 2007, the MLP closed its previously announced acquisition of natural gas, crude oil and related assets in Michigan, Indiana and Kentucky from Quicksilver Resources Inc. for USD $750 million in cash and approximately 21.3 million common units of the MLP. The acquisition is comprised of natural gas producing assets located primarily in the Michigan Antrim Shale. The cash portion of the purchase price will be funded by a private placement of new MLP units and bank debt. As a result of this transaction, the Trust's interest in the MLP has decreased from approximately 50 percent to approximately 22 percent. A related dilution gain is expected to be recorded in the fourth quarter of 2007. The Trust continues to control the MLP through its 95.6 percent ownership of the general partner. At September 30, 2007, a deposit of USD $35 million related to this acquisition is included in prepaid expenses and other current assets.

Canadian acquisition announced

On October 22, 2007, the Trust announced that it has reached an acquisition agreement with Triwest Energy Inc. (Triwest), a privately held company with oil assets in southeast Saskatchewan. Pursuant to the agreement, the Trust has made an offer to acquire all outstanding shares of Triwest for an exchange of approximately 6.25 million Trust units. The Trust will also assume Triwest's debt and working capital deficiency of approximately $13 million. The Trust expects the transaction to close near the end of November 2007.

12. Segmented information

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

Oil and natural gas production in Canada and the USA 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 and the USA in the oil and gas production business segment. The geographic components have been presented as well as the midstream business that operates in both Canada and the USA.



Three months ended September 30, 2007
-------------------------------------------------------------
United
Canada Oil States
and Oil and Total Oil
Natural Natural and
Gas Gas Natural
Production Production Gas Midstream
(COGP) (USOGP) Production (1) Total
----------------------------------------------------------------------------
Revenue
Gross
production
revenue $ 111,466 $ 74,157 $ 185,623 $ - $ 185,623
Royalties (22,464) (7,784) (30,248) - (30,248)
Product sales
and service
revenue - - - 457,307 457,307
Realized (loss)
gain on
financial
derivative
instruments 3,417 (3,251) 166 (23,357) (23,191)
----------------------------------------------------------------------------
92,419 63,122 155,541 433,950 589,491
Expenses
Cost of goods
sold - 5,404 5,404 373,996 379,400
Production,
operating and
maintenance 31,378 19,686 51,064 2,939 54,003
Transportation 3,004 1,541 4,545 3,370 7,915
Foreign
exchange gain
and other (1,892) - (1,892) (1) (1,893)
General and
administrative 6,399 7,498 13,897 6,221 20,118
----------------------------------------------------------------------------
----------------------------------------------------------------------------
38,889 34,129 73,018 386,525 459,543
----------------------------------------------------------------------------
Earnings before
interest,
taxes,
depletion,
depreciation,
accretion and
other non-cash
items 53,530 28,993 82,523 47,425 129,948
Other revenue
Unrealized loss
on financial
derivative
instruments (1,400) (23,938) (25,338) (30,904) (56,242)
----------------------------------------------------------------------------

Other expenses
Depletion,
depreciation
and accretion 72,288 11,004 83,292 11,218 94,510
Interest on
bank debt 3,280 843 4,123 9,839 13,962
Interest and
accretion on
convertible
debentures 887 2,736 3,623 2,660 6,283
Amortization of
deferred
financing
charges - - - - -
Unrealized
foreign
exchange loss
(gain) and
other 27 - 27 977 1,004
Dilution gain - - - - -
Non-cash unit
based
compensation 3,701 2,305 6,006 4,896 10,902
Internal
management
charge (361) 361 - - -
Capital tax
expense 2,364 - 2,364 - 2,364
Current and
withholding tax
expense 19 34 53 3,440 3,493
Future income
tax (recovery)
expense (12,268) 845 (11,423) (7,879) (19,302)
----------------------------------------------------------------------------
----------------------------------------------------------------------------
69,937 18,128 88,065 25,151 113,216
Non-controlling
interest -
USOGP - (4,505) (4,505) - (4,505)
Non-controlling
interest -
exchangeables - - - - -
----------------------------------------------------------------------------
Net loss for
the period $ (17,807) $ (8,568) $ (26,375) $ (8,630) $ (35,005)
----------------------------------------------------------------------------
----------------------------------------------------------------------------

(1) Included in the Midstream segment is product sales and service revenue
of $46.8 million associated with U.S. operations.



As at and for the three months ended September 30, 2007
-------------------------------------------------------------
United
Canada Oil States
and Oil and Total Oil
Natural Natural and
Gas Gas Natural
Production Production Gas
(COGP) (USOGP) Production Midstream Total
----------------------------------------------------------------------------
Selected
balance
sheet
items
Capital
assets
Property,
plant
and
equipment
net $ 1,664,934 $ 572,923 $ 2,237,857 $ 719,925 $ 2,957,782
Intangible
assets - 2,937 2,937 176,900 179,837
Goodwill 417,614 - 417,614 100,409 518,023
Capital
expenditures
Capital
Expenditures 33,660 17,530 51,190 3,127 54,317
Corporate
acquisitions - - - - -
Oil and gas
property
acquisitions,
net 1,860 400 2,260 - 2,260
Goodwill
additions - - - - -
Working
capital
Accounts
receivable 64,196 33,267 97,463 187,394 284,857
Petroleum
product
inventory - 2,286 2,286 134,446 136,732
Accounts
payable and
accrued
liabilities 131,083 52,656 183,739 202,201 385,940
Long-term
debt $ 267,770 $ 170,399 $ 438,169 $ 778,967 $ 1,217,136
----------------------------------------------------------------------------
----------------------------------------------------------------------------


Three months ended September 30, 2006
-------------------------------------------------------------
United
Canada Oil States
and Oil and Total Oil
Natural Natural and
Gas Gas Natural
Production Production Gas Midstream
(COGP) (USOGP) Production (1) Total
----------------------------------------------------------------------------
Revenue
Gross
production
revenue $ 93,375 $ 47,788 $ 141,163 - $ 141,163
Royalties (19,564) (4,677) (24,241) - (24,241)
Product sales
and service
revenue - - - 470,575 470,575
Realized (loss)
gain on
financial
derivative
instruments 1,955 (2,195) (240) (10,972) (11,212)
----------------------------------------------------------------------------
75,766 40,916 116,682 459,603 576,285
Expenses
Cost of goods
sold - - - 384,306 384,306
Production,
operating and
maintenance 22,865 12,771 35,636 1,643 37,279
Transportation 805 - 805 2,237 3,042
Foreign
exchange gain
and other 271 - 271 (91) 180
Cash general
and
administrative 6,490 5,730 12,220 5,550 17,770
----------------------------------------------------------------------------
30,431 18,501 48,932 393,645 442,577
----------------------------------------------------------------------------

Earnings before
interest,
taxes,
depletion,
depreciation,
accretion and
other non-cash
items 45,335 22,415 67,750 65,958 133,708
Other revenue
Unrealized gain
on financial
derivative
instruments 14,346 23,024 37,370 47,367 84,737
----------------------------------------------------------------------------

Other expenses
Depletion,
depreciation
and accretion 41,247 6,480 47,727 10,915 58,642
Interest on
bank debt 2,520 1,774 4,294 5,040 9,334
Interest and
accretion on
convertible
debentures 1,612 1,135 2,747 3,225 5,972
Amortization of
deferred
financing
charges 260 183 443 520 963
Unrealized
foreign
exchange loss
(gain) and
other - - - (862) (862)
Dilution gain - - - - -
Non-cash unit
based
compensation 1,208 777 1,985 940 2,925
Internal
management
charge (239) 239 - - -
Capital tax
expense 259 - 259 - 259
Current and
withholding tax
recovery - (763) (763) (565) (1,328)
Future income
tax (recovery)
expense (9,765) 18,117 8,352 11,054 19,406
----------------------------------------------------------------------------
37,102 27,942 65,044 30,267 95,311
Non-controlling
interest -
USOGP - 1,929 1,929 - 1,929
Non-controlling
interest -
exchangeables (42) 72 30 325 355
----------------------------------------------------------------------------

Net income for
the period $ 22,621 $ 15,496 $ 38,117 $ 82,733 $ 120,850
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(1) Included in the Midstream segment is product sales and service revenue
of $56.2 million associated with U.S. operations.


As at and for the three months ended September 30, 2006
-------------------------------------------------------------
United
Canada Oil States
and Oil and Total Oil
Natural Natural and
Gas Gas Natural
Production Production Gas
(COGP) (USOGP) Production Midstream Total
----------------------------------------------------------------------------
Selected
balance
sheet items
Capital
assets
Property,
plant
and equipment
net $1,218,836 $ 354,071 $ 1,572,907 $ 724,669 $ 2,297,576
Intangible
assets - - - 199,157 199,157
Goodwill 330,944 - 330,944 102,402 433,346
Capital
expenditures
Capital
expenditures 14,496 13,482 27,978 10,276 38,254
Corporate
acquisitions - - - - -
Oil and gas
property
acquisitions,
net 472,731 - 472,731 - 472,731
Goodwill
additions - - - - -
Working
capital
Accounts
receivable 46,893 23,870 70,763 207,200 277,963
Petroleum
product
inventory - - - 128,198 128,198
Accounts
payable
and accrued
liabilities 69,417 57,126 126,543 164,970 291,513
Long-term
debt $ 522,468 $ 174,157 $ 696,625 $ 464,416 $ 1,161,041
----------------------------------------------------------------------------
----------------------------------------------------------------------------


Nine months ended September 30, 2007
-------------------------------------------------------------
United
Canada Oil States
and Oil and Total Oil
Natural Natural and
Gas Gas Natural
Production Production Gas Midstream
(COGP) (USOGP) Production (1) Total
----------------------------------------------------------------------------
Revenue
Gross
production
revenue $ 329,122 $ 170,160 $ 499,282 $ - $ 499,282
Royalties (63,236) (17,383) (80,619) - (80,619)
Product sales
and service
revenue - - - 1,320,778 1,320,778
Realized
(loss) gain on
financial
derivative
instruments 1,229 879 2,108 (35,843) (33,735)
----------------------------------------------------------------------------
267,115 153,656 420,771 1,284,935 1,705,706
Expenses
Cost of goods
sold - 11,143 11,143 1,104,913 1,116,056
Production,
operating and
maintenance 82,743 51,763 134,506 10,358 144,864
Transportation 6,299 1,980 8,279 11,099 19,378
Foreign
exchange gain
and other (2,189) - (2,189) (1) (2,190)
General and
administrative 21,519 34,471 55,990 22,314 78,304
----------------------------------------------------------------------------
108,372 99,357 207,729 1,148,683 1,356,412
----------------------------------------------------------------------------
Earnings
before
interest,
taxes,
depletion,
depreciation,
accretion and
other non-cash
items 158,743 54,299 213,042 136,252 349,294
Other revenue
Unrealized
loss on
financial
derivative
instruments (4,096) (45,131) (49,227) (31,087) (80,314)
----------------------------------------------------------------------------

Other expenses
Depletion,
depreciation
and accretion 185,858 28,052 213,910 33,529 247,439
Interest on
bank debt 7,666 2,941 10,607 22,997 33,604
Interest and
accretion on
convertible
debentures 2,766 8,028 10,794 8,298 19,092
Amortization
of deferred
financing
charges - - - - -
Unrealized
foreign
exchange loss
(gain) and
other (890) - (890) 2,832 1,942
Dilution gain - (98,592) (98,592) - (98,592)
Non-cash unit
based
compensation 6,712 104 6,816 8,990 15,806
Internal
management
charge (1,143) 1,143 - - -
Capital tax
expense 3,252 - 3,252 - 3,252
Current and
withholding
tax expense 57 266 323 6,300 6,623
Future income
tax (recovery)
expense (2) (77,743) 44,621 (33,122) 121,202 88,080
----------------------------------------------------------------------------
126,535 (13,437) 113,098 204,148 317,246
Non-controlling
interest -
USOGP - (10,155) (10,155) - (10,155)
Non-controlling
interest -
exchangeables - - - - -
----------------------------------------------------------------------------
Net (loss)
income for the
period $ 28,112 $ 32,760 $ 60,872 $ (98,983) $ (38,111)
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(1) Included in the Midstream segment is product sales and service revenue
of $181.0 million associated with U.S. operations.
(2) Future income tax (recovery) expense includes a charge of $105.7 million
relating to the enactment of Bill C-52, Budget Implementation Act 2007
by the Canadian government (see note 10).


As at and for the nine months ended September 30, 2007
-------------------------------------------------------------
United
Canada Oil States
and Oil and Total Oil
Natural Natural and
Gas Gas Natural
Production Production Gas
(COGP) (USOGP) Production Midstream Total
----------------------------------------------------------------------------
Selected
balance
sheet items
Capital
assets
Property,
plant and
equipment
net $ 1,664,934 $ 572,923 $ 2,237,857 $ 719,925 $ 2,957,782
Intangible
assets - 2,937 2,937 176,900 179,837
Goodwill 417,614 - 417,614 100,409 518,023
Capital
expenditures
Capital
Expenditures 93,664 50,857 144,521 9,236 153,757
Corporate
acquisitions 467,850 - 467,850 - 467,850
Oil and gas
property
acquisitions,
net 11,569 250,844 262,413 - 262,413
Goodwill
additions 86,670 - 86,670 - 86,670
Working
capital
Accounts
receivable 64,196 33,267 97,463 187,394 284,857
Petroleum
product
inventory - 2,286 2,286 134,446 136,732
Accounts
payable and
accrued
liabilities 131,083 52,656 183,739 202,201 385,940
Long-term
debt $ 267,770 $ 170,399 $ 438,169 $ 778,967 $ 1,217,136


Nine months ended September 30, 2006
-------------------------------------------------------------
United
Canada Oil States
and Oil and Total Oil
Natural Natural and
Gas Gas Natural
Production Production Gas Midstream
(COGP) (USOGP) Production (1) Total
----------------------------------------------------------------------------
Revenue
Gross
production
revenue $ 298,670 $ 135,974 $ 434,644 $ - $ 434,644
Royalties (61,665) (13,358) (75,023) - (75,023)
Product sales
and service
revenue - - - 1,322,545 1,322,545
Realized
(loss) gain on
financial
derivative
instruments 1,222 (4,397) (3,175) (20,803) (23,978)
----------------------------------------------------------------------------
238,227 118,219 356,446 1,301,742 1,658,188
Expenses
Cost of goods
sold - - - 1,111,151 1,111,151
Production,
operating and
maintenance 69,324 36,474 105,798 19,524 125,322
Transportation 3,591 - 3,591 9,294 12,885
Foreign
exchange gain
and other (39) - (39) (347) (386)
Cash general
and
administrative 17,655 19,680 37,335 16,911 54,246
----------------------------------------------------------------------------
90,531 56,154 146,685 1,156,533 1,303,218
----------------------------------------------------------------------------
Earnings
before
interest,
taxes,
depletion,
depreciation,
accretion and
other non-cash
items 147,696 62,065 209,761 145,209 354,970
Other revenue
Unrealized
(loss) gain on
financial
derivative
instruments 17,267 3,326 20,593 (39,614) (19,021)
----------------------------------------------------------------------------

Other expenses
Depletion,
depreciation
and accretion 110,336 21,789 132,125 32,530 164,655
Interest on
bank debt 6,346 4,466 10,812 12,692 23,504
Interest and
accretion on
convertible
debentures 4,892 3,443 8,335 9,784 18,119
Amortization
of deferred
financing
charges 756 532 1,288 1,512 2,800
Unrealized
foreign
exchange loss
(gain) and
other - - - (663) (663)
Dilution gain - - - - -
Non-cash unit
based
compensation 3,138 4,676 7,814 2,458 10,272
Internal
management
charge (750) 750 - - -
Capital tax
expense 862 - 862 - 862
Current and
withholding
tax expense - 4,396 4,396 - 4,396
Future income
tax (recovery)
expense (52,655) 15,876 (36,779) (18,790) (55,569)
----------------------------------------------------------------------------
72,925 55,928 128,853 39,523 168,376
Non-controlling
interest -
USOGP - 547 547 - 547
Non-controlling
interest -
exchangeables 336 37 373 232 605
----------------------------------------------------------------------------
Net income for
the period $ 91,702 $ 8,879 $ 100,581 $ 65,840 $ 166,421
----------------------------------------------------------------------------
----------------------------------------------------------------------------

(1) Included in the Midstream segment is product sales and service revenue
of $236.6 million associated with U.S. operations.

as at and for the nine months ended September 30, 2006
-------------------------------------------------------------
United
Canada Oil States
and Oil and Total Oil
Natural Natural and
Gas Gas Natural
Production Production Gas
(COGP) (USOGP) Production Midstream Total
----------------------------------------------------------------------------
Selected
balance sheet
items
Capital
assets
Property,
plant and
equipment
net $ 1,218,836 $ 354,071 $ 1,572,907 $ 724,669 $ 2,297,576
Intangible
assets - - - 199,157 199,157
Goodwill 330,944 - 330,944 102,402 433,346
Capital
expenditures
Capital
expenditures 51,813 40,023 91,836 37,686 129,522
Corporate
acquisitions - - - 2,300 2,300
Oil and gas
property
acquisitions,
net 474,955 (2,008) 472,947 - 472,947
Goodwill
additions - - - 4,278 4,278
Working
capital
Accounts
receivable 46,893 23,870 70,763 207,200 277,963
Petroleum
product
inventory - - - 128,198 128,198
Accounts
payable and
accrued
liabilities 69,417 57,126 126,543 164,970 291,513
Long-term
debt $ 522,468 $ 174,157 $ 696,625 $ 464,416 $ 1,161,041
----------------------------------------------------------------------------

Contact Information

  • Provident Energy Trust
    Laurie Stretch
    Senior Manager, Investor Relations and Communications
    Phone: (403) 231-6710
    Email: info@providentenergy.com
    or
    Corporate Head Office:
    800, 112 - 4th Avenue S.W.
    Calgary, Alberta T2P 0H3
    (403) 296-2233 or Toll Free: 1-800-587-6299
    (403) 294-0111 (FAX)
    Website: www.providentenergy.com