Provident Energy Trust
TSX : PVE.UN
AMEX : PVX

Provident Energy Trust

November 09, 2005 09:00 ET

Provident Energy Announces Third Quarter 2005 Results

CALGARY, ALBERTA--(CCNMatthews - Nov. 9, 2005) - Provident Energy Trust (TSX:PVE.UN) (AMEX:PVX):

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

Third quarter 2005 highlights

- Cash flow and earnings rise on strength of commodity prices.

- Payout ratio drops to 69 percent, strengthening the sustainability of the Trust.

- Non-core property disposition completed for cash proceeds of $44.6 million.

Provident Energy Trust (Provident) reported third quarter 2005 cash flow from operations of $86.3 million ($0.53/unit) compared to $54.1 million ($0.41/unit) generated in the third quarter of 2004, an increase of 60 percent. Distributions declared in the quarter totaled $59.3 million ($0.36/unit) compared to $46.5 million ($0.36/unit) in 2004. For the third quarter of 2005, Provident's payout ratio of cash flow from operations was 69 percent compared to 86 percent in the same period of 2004.

Year-to-date, operating cash flow was $214.9 million ($1.37/unit) compared to $126.9 million ($1.20/unit) for the same period in 2004, an increase of 69 percent. For the nine months ended September 30, 2005, Provident declared distributions of $168.1 million ($1.08/unit) compared to $112.6 million ($1.08/unit) during the same period in 2004. Provident's year-to-date payout ratio is 78 percent, compared to 89 percent for the same period in 2004. Based on the current distribution level and commodity prices, Provident forecasts a payout ratio in the range of 75 to 80 percent for 2005.

"Third quarter and year-to-date results were in line with expectations," said Provident Chief Executive Officer Tom Buchanan. "With our current businesses performing well, we are looking forward to integrating the $697 million acquisition of EnCana's NGL business that we announced after the end of the quarter."

On September 29, 2005, Provident disposed of various non-core properties and land in Saskatchewan and Alberta for cash proceeds of $44.6 million. "This disposition is in line with Provident's ongoing strategy to focus our portfolio on those assets that can provide maximum value and lowest operating costs for our unitholders," said Provident's President Randy Findlay.

Business Unit Results

Provident owns diversified investments across the energy value chain in Canada and the United States. The company comprises three key business units: Midstream Services and Marketing (Midstream), U.S. Oil and Gas Production (USOGP), and Canadian Oil and Gas Production (COGP). The results for each of these business units are summarized below.

Midstream Services and Marketing (Midstream)

Provident's Midstream business unit generates cash flow by providing fee-based services, from the extraction, transportation, storage, distribution and marketing of natural gas liquids (NGLs), to petroleum producers and refiners, petrochemical companies, and marketing firms. Provident's Midstream assets include 100 percent ownership of the Redwater NGL Fractionation and Storage Facility, the most modern and low-cost NGL processing system of its kind in Western Canada. Assets also include 100 percent ownership of the proprietary Liquids Gathering System (LGS), and 43.3 percent ownership of the Younger Extraction Plant. Investors should note that early in the fourth quarter, Provident announced a major NGL business acquisition, which will greatly expand the Trust's midstream operations. That acquisition is expected to close before the end of the year.

For the third quarter of 2005, Provident's Midstream business unit generated earnings before interest, taxes, depreciation, accretion, and non-cash revenue (EBITDA) of $13.0 million, an 18 percent increase over the $11.0 million generated in third quarter of 2004. Cash flow from operations increased 32 percent from the third quarter of 2004, rising from $9.3 million to $12.2 million. The increase in EBITDA and cash flow was due to efficient operations, enhanced marketing activities, and increased revenue from NGL storage and distribution services. Provident managed 61,760 barrels per day (bpd) over the third quarter. Product managed in the third quarter of 2004 was 58,400 bpd, which was marginally impacted by an outage on the LGS. Year-to-date managed volumes averaged 59,870 bpd compared with 59,250 bpd for the first nine months of 2004.

Year-to-date, Midstream has generated EBITDA of $41.1 million. This compares with $32.1 million generated in the nine months ended September 30, 2004. Midstream's year-to-date cash flow for 2005 was $37.9 million, an increase of 46 percent from the $26.1 million cash flow generated during the same period last year.

U.S. Oil and Gas Production (USOGP)

Provident's USOGP business unit generates cash flow from the production and sale of natural gas and crude oil from basins in Southern California and Wyoming. BreitBurn Energy LP (Breitburn) operates 100 percent of the production, and Provident owns approximately 96 percent of Breitburn. Provident acquired BreitBurn on June 15, 2004 and, therefore, the results for the 15 days ended June 30, 2004 are immaterial.

In the third quarter of 2005, USOGP generated $18.7 million of cash flow from operations, and production averaged 7,824 boed. Production over the period was weighted 96 percent light/medium crude oil and four percent natural gas. USOGP increased its production in the third quarter of 2005 by 119 percent when compared with production during the third quarter of 2004. This increase is primarily due to the addition of the first full quarter of production from the Nautilus properties in Wyoming, which were acquired on March 2, 2005 and the acquisition of the Orcutt properties on October 4, 2004.

Operating netbacks before hedging in the third quarter of 2005 remain strong at $43.03, driven by high commodity prices. Operating costs were $14.80 per barrel of oil equivalent (boe) during the third quarter, compared with $15.74 per boe during the third quarter of 2004. USOGP operations are continuing to return to, or maintain, production on wells with higher operating costs due to persistence of strong crude oil prices. Year-to-date, operating costs at $14.23 per boe were nine percent lower than the $15.62 reported in the period from June 15 to December 31, 2004.

Provident spent $11.2 million on USOGP capital expenditures during the third quarter. $8.1 million was directed to drilling, optimization and facility upgrades at its West Pico, Santa Fe Springs, and Orcutt operations. Provident also directed $1.4 million to optimization projects at the Nautilus fields and $1.7 million on optimization projects at smaller fields and office equipment.

Canadian Oil and Gas Production (COGP)

Provident's COGP business unit generates cash flow from the production and sale of natural gas, light/medium oil, natural gas liquids (NGLs), and heavy oil to energy marketers. Production assets are primarily located in the central and southern regions of Alberta and Saskatchewan.

In the third quarter of 2005, COGP generated $55.5 million in cash flow from operations, compared to $35.2 million in the third quarter of 2004. Third quarter 2005 production averaged 25,945 boed compared to the 32,453 average boed for the same period last year. Production was weighted 47 percent natural gas, 37 percent medium/light crude oil and NGLs, and 16 percent heavy oil. Year-to-date, Provident's COGP production averaged 27,464 boed, compared to a 27,746 boed average during the same period last year. The decrease reflects natural production declines partially offset by drilling and optimization activities.

The non-core properties that were sold in September averaged 2,100 boed of production for the period July 1, 2005 to September 28, 2005, including approximately 1,010 bpd of heavy oil. Proved plus probable reserves for the properties were 6,397 Mboe. Approximately 87,850 net acres of land were also included. These assets were divested due to their higher operating costs and lower netbacks. The proceeds will be used to fund Provident's ongoing capital program and to pay down debt.

Third quarter 2005 operating netback of $32.90 per boe was 49 percent above the $22.04 per boe in the same quarter of 2004. The year-to-date operating netback of $26.28 was 21 percent above the comparable nine-month period in 2004 of $21.70 per boe. The increase in 2005 reflects a higher WTI crude oil benchmark and a significant shift in Provident's production mix.

Operating costs were $10.03 per boe during the third quarter of 2005, compared to $9.05 per boe during the third quarter of 2004, an 11 percent increase. Operating expenses increased in a number of categories, including well servicing, maintenance, power and fuel, and fluid hauling. Poor weather conditions in the second quarter of 2005 delayed well servicing and maintenance costs into the third quarter. That factor combined with natural production declines resulted in higher operating costs.

In the third quarter, Provident spent $28.5 million in COGP capital expenditures. $12.8 million was spent in the southeast and southwest Saskatchewan core areas on acquiring mineral rights for future development, shallow gas drilling, recompletions and facility work. In southern Alberta, $8.9 million was spent on drilling activities, recompletions, facility upgrades, seismic and mineral rights acquisitions. In the Lloydminster area, $3.4 million was spent primarily on drilling and facility work, while west central Alberta spent $2.8 million on non-operated drilling and facility work. A further $0.6 million was spent on office and other items.

Federal Tax Consultation Process

On September 8, 2005 the Government of Canada issued a consultation paper entitled "Tax and Other Issues Related to Publicly Listed Flow-Through Entities," regarding the tax treatment of income trusts. Provident has received questions from unitholders about the significance of this process and what if any changes may result. Provident recognizes the government's responsibility to ensure appropriate tax policy, and appreciates the opportunity to participate in the consultation. Below is Provident's view on the issues under debate, and information for investors who may wish to express their views directly.

The government's consultation paper discusses two potential issues around flow-through entities such as income trusts: tax revenue implications and economic efficiency concerns. Provident believes that the consultation process will demonstrate that the current trust structure benefits both the Canadian economy and Canadian taxpayers.

Given Canada's aging population, the Government of Canada has wisely encouraged Canadians to save for retirement. Income trusts offer individual investors a tax effective form of income, and an attractive way to participate in Canada's equity markets. And those individual investors have been well rewarded for investing in income trusts. Provident alone has provided its unitholders with a total return of 342 percent since its inception in March 2001. This is a total payout to investors of well over half a billion dollars. That payout is taxed at personal tax rates that are typically higher than corporate rates, or in the case of foreign investors, taxed through a withholding tax.

Income trusts boost national productivity and foster innovation. Provident's recent acquisition of a major continental NGL business is an excellent example of how the trust structure works to promote Canadian ownership and disciplined management of assets in mature industries.

Provident believes that the rapid growth in the trust sector and the strong returns that the sector has provided to investors demonstrate the effectiveness of this uniquely Canadian legal structure. Imposing a higher tax burden on income trusts would serve only to punish individual investors, while creating nervousness in capital markets about the stability of the Canadian tax regime. However, a review of the overall rate of corporate tax in Canada, including the taxation policy on corporate dividends, would likely yield options for leveling the playing field between corporations and income trusts. More broadly, Provident believes that today's strong Canadian economy demonstrates the value of past government policies that have encouraged open flows of capital and reduced overall taxation levels.

Provident encourages its unitholders to participate in the federal consultation process by expressing their views on this issue. Comments can be sent by e-mail to trusts-fiducies@fin.gc.ca, or directly to the Finance Minister at goodale.r@parl.gc.ca. The mailing address is: Denis Normand, Tax Policy Branch, Business Income Tax Division, Department of Finance, 17th floor, East Tower, 140 O'Connor Street, Ottawa, Ontario, K1A 0G5. Canadian unitholders can also contact their own Member of Parliament, with names and addresses available at www.parl.gc.ca.

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



Consolidated financial highlights

Three months ended Nine months ended
Consolidated September 30, September 30,
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($000s except 2005 2004 % 2005 2004 %
per unit data) (1)(4) Change (1)(4) Change
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Revenue (net of
royalties and
financial
derivative
instruments) $295,060 $287,171 3 $917,587 $740,422 24
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Cash flow
from COGP
operations $ 55,470 $ 35,167 58 $133,137 $ 90,871 47
Cash flow
from USOGP
operations 18,669 9,658 93 43,807 9,933 341
Cash flow
from midstream
services and
marketing 12,179 9,251 32 37,946 26,071 46
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Total cash
flow from
operations $ 86,318 $ 54,076 60 $214,890 $126,875 69
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Per weighted
average
unit -
basic (2) $ 0.53 $ 0.41 30 $ 1.37 $ 1.20 14
Per weighted
average
unit -
diluted (3) $ 0.53 $ 0.41 30 $ 1.37 $ 1.20 14
Declared
distributions
to
unitholders $ 59,333 $ 46,489 28 $168,068 $112,564 49
Per unit (2) $ 0.36 $ 0.36 - $ 1.08 $ 1.08 -
Percent of
cash flow
from
operations
paid out as
declared
distributions 69% 86% (20) 78% 89% (12)
Net income
(loss) $ 18,386 $ (4,221) - $ 42,425 $(17,089) -
Per weighted
average
unit -
basic (2) $ 0.11 $ (0.03) - $ 0.27 $ (0.16) -
Per weighted
average
unit -
diluted (3) $ 0.11 $ (0.03) - $ 0.27 $ (0.16) -
Capital
expenditures $ 39,402 $ 26,724 47 $105,488 $ 49,850 112
Nautilus
acquisition $ - $ - - $ 91,420 $ - -
Property
acquisitions $ 680 $ 3,991 (83) $ 680 $ 8,709 (92)
Property
dispositions $ 44,639 $ - - $ 44,639 $ 7,114 527
Weighted
average
trust units
outstanding
(000s)
- Basic(2) 164,218 130,911 25 156,806 105,574 49
- Diluted(3) 164,543 131,006 25 157,131 105,670 49
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Consolidated
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As at As at
September 30, December 31, %
($000s) 2005 2004 Change
---------------------------------------------------------------------
Long-term debt $ 341,250 $ 432,206 (21)
Unitholders' equity $ 1,136,521 $ 1,009,048 13
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(1) Restated for the impact of the retroactive implementation of the
change in accounting policies for convertible debentures - see
note 2
(2) Excludes exchangeable shares
(3) Includes unit options
(4) Restated for the impact of the retroactive implementation of
change in accounting policies for exchangeable securities -
non-controlling interest - see note 2


Operational highlights

Three months ended Nine months ended
Consolidated September 30, September 30,
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% %
2005 2004 Change 2005 2004 Change
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Oil and Gas Production
Daily production
Light/medium
crude
oil (bpd) 15,583 12,674 23 15,288 8,848 73
Heavy oil
(bpd) 4,075 6,770 (40) 4,750 6,632 (28)
Natural gas
liquids (bpd) 1,523 1,803 (16) 1,577 1,401 13
Natural gas
(mcfpd) 75,523 88,642 (15) 78,353 75,557 4
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Oil
equivalent
(boed)(1) 33,768 36,021 (6) 34,674 29,141 19
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Average selling
price (before
hedges)
Light/medium
crude
oil ($/bbl) $ 62.95 $ 48.59 30 $ 54.51 $ 44.44 23
Heavy oil
($/bbl) $ 46.74 $ 34.23 37 $ 31.95 $ 29.84 7
Corporate
oil blend
($/bbl) $ 59.59 $ 43.41 37 $ 49.16 $ 38.19 29
Natural gas
liquids
($/bbl) $ 54.27 $ 40.88 33 $ 48.96 $ 39.78 23
Natural gas
($/mcf) $ 8.43 $ 6.47 30 $ 7.48 $ 6.62 13
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Oil
equivalent
($/boe)(1) $ 56.00 $ 41.98 33 $ 47.55 $ 38.91 22
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Field
netback
(before
hedges)
($/boe) $ 35.21 $ 23.11 52 $ 28.56 $ 22.11 29
Field
netback
(including
hedges)
($/boe) $ 28.25 $ 16.78 68 $ 23.64 $ 16.19 46
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Midstream services and marketing
Redwater
managed
volumes
(bpd) 61,760 58,400 6 59,870 59,250 1
EBITDA
(000s)(2) $ 12,978 $ 10,986 18 $ 41,123 $ 32,128 28
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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 non-cash revenue.


Management's discussion and analysis

The following analysis provides a detailed explanation of Provident's operating results for the quarter and for the nine months ended September 30, 2005 compared to same time periods in 2004 and should be read in conjunction with the consolidated financial statements of Provident, found later in the interim report.

This disclosure contains certain forward-looking estimates that involve substantial known and unknown risks and uncertainties, certain of which are beyond Provident's control. These include the impact of general economic conditions in Canada and the United States; industry conditions; changes in laws and regulations including the adoption of new environmental laws and regulations and changes in how they are interpreted and enforced; increased competition; the lack of availability of qualified personnel or management; fluctuations in commodity prices; foreign exchange or interest rates; stock market volatility and obtaining required approvals of regulatory authorities. Provident's actual results, performance or achievement could differ materially from those expressed in, or implied by, these forward-looking estimates and, accordingly, no assurances can be given that any of the events anticipated by the forward-looking estimates will transpire, or if any of them do so, what benefits, including the amounts of proceeds, Provident will derive there from. All amounts are reported in Canadian dollars, unless otherwise stated.

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 and exploitation ("COGP"), United States crude oil and natural gas production and exploitation, ("USOGP") and midstream services and marketing ("Midstream"). Provident's COGP business produces crude oil and natural gas from five core areas in the western Canadian sedimentary basin. USOGP produces crude oil and natural gas in southern California and Wyoming, U.S.A. The Midstream business unit processes, markets, transports and offers storage of natural gas liquids at the Redwater facility and surrounding infrastructure located north of Edmonton, Alberta. The unit also markets natural gas liquids, natural gas and crude oil.

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.

Third quarter and nine months ended September 30, 2005 highlights

The third quarter highlights section provides commentary for the third quarter and for the nine months ended September 30, 2005 results compared to the corresponding periods in 2004.

USOGP comparative discussion and analysis for the three months and nine months ended September 30, 2004 have been provided within the MD&A, however, the nine months ended September 30, 2004 have not been disclosed in the USOGP segment as the USOGP operations were incorporated into Provident's results for June 15, 2004 and second quarter 2004 results were immaterial.



Consolidated cash flow from operations and cash distributions

Three months ended Nine months ended
Consolidated September 30, September 30,
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($000s except % %
per unit data) 2005 2004 Change 2005 2004 Change
---------------------------------------------------------------------
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Revenue, Cash Flow and Distributions
Revenue (net of
royalties and
financial
derivative
instruments
- see note 9
of the
financial
statements) $295,060 $287,171 3 $917,587 $740,422 24
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Cash flow from
operations
before
changes
in working
capital
and site
restoration
expenditures $ 86,318 $ 54,076 60 $214,890 $126,875 69
Per weighted
average
unit -
basic (1) $ 0.53 $ 0.41 30 $ 1.37 $ 1.20 14
Per weighted
average
unit -
diluted
(2) $ 0.53 $ 0.41 30 $ 1.37 $ 1.20 14
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Declared
distrib-
utions $ 59,333 $ 46,489 28 $168,068 $112,564 49
Per Unit (1) 0.36 0.36 - 1.08 1.08 -
Percent of
cash flow
distributed 69% 86% (20) 78% 89% (12)
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(1) Excludes exchangeable shares
(2) Includes unit options


Third quarter 2005 cash flow was $86.3 million, 60 percent above the $54.1 million of cash flow recorded in the third quarter of 2004. For the nine month period ended September 30, 2005 cash flow was $214.9 million, 69 percent above the $126.9 million of cash flow in the same period of 2004.

COGP 2005 third quarter cash flow was $55.5 million, a 58 percent improvement above the $35.2 million recorded in the comparable 2004 quarter. The main driver for this increase was improved product pricing, product mix and netbacks, as well as effective drilling programs offset by natural production declines. For the nine month period ended September 30, 2005 COGP cash flow was $133.1 million, a 47 percent improvement above the $90.9 million recorded in the comparable 2004 period. The Midstream business unit added $12.2 million to third quarter 2005 cash flow, 32 percent above the $9.3 million recorded in the comparable 2004 quarter.

The Midstream cash flow benefited from efficient operations, marketing opportunities and increased revenues associated with storage and distribution services. For the nine month period ended September 30, 2005 the Midstream business unit added $37.9 million to cash flow, a 46 percent improvement above the $26.1 million recorded in the comparable 2004 period.

Cash flow from operations in the third quarter of 2005 also reflects cash flow of $18.7 million from the USOGP business unit, 93 percent above the $9.7 million in the comparable 2004 quarter. For the nine month period ended September 30, 2005 cash flow was $43.8 million.

Declared distributions in the third quarter of 2005 totaled $59.3 million compared to $46.5 million of declared distributions in 2004. This represented 69 percent and 86 percent of cash flow from operations respectively.

Management uses cash flow from operations (before changes in working capital and site restoration expenditures) to analyze operating performance. Cash flow 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. Cash flow as presented is not intended to represent operating cash flow or operating profits for the period nor should it be viewed as an alternative to cash flow from operating activities, net earnings or other measures of financial performance calculated in accordance with GAAP. All references to cash flow throughout this report are based on cash flow before changes in non-cash working capital and site restoration expenditures.



Net income (loss)

Three months ended Nine months ended
Consolidated September 30, September 30,
---------------------------------------------------------------------
($000s except 2005 2004 % 2005 2004 %
per unit data) (3) Change (3) Change
---------------------------------------------------------------------
---------------------------------------------------------------------
Net income
(loss) $ 18,386 $ (4,221) - $ 42,425 $(17,089) -
Per weighted
average
unit
- basic (1) $ 0.11 $ (0.03) - $ 0.27 $ (0.16) -
Per weighted
average
unit
- diluted(2) $ 0.11 $ (0.03) - $ 0.27 $ (0.16) -
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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 unit option plan
(3) Restated - note 2.


Net income for the third quarter of 2005 improved to $18.4 million compared to a $4.2 million net loss in the comparable 2004 quarter. Increased income is attributable to a full quarter of production resulting from the late second quarter 2004 acquisitions of Viracocha, Olympia and BreitBurn and improved matching of non-cash hedging losses with their underlying revenue streams.

The COGP business segment's net income is $2.6 million, an improvement to the 2004 third quarter loss of $23.3 million mainly due to improved product pricing, product mix and netbacks, as well as effective drilling programs offset by natural production declines. The COGP business segment's net income for the nine months ended September 30, 2005 is $0.4 million, an improvement to the $46.1 million net loss in the comparable 2004 period.

The Midstream unit contributed $7.7 million of net income in the third quarter of 2005 as compared to the $13.1 million of net income in the third quarter of 2004. The Midstream unit contributed $32.1 million of net income in the nine months ended September 30, 2005 as compared to the $21.0 million of net income in the comparable 2004 period.

In the third quarter of 2005, USOGP net income was $8.1 million comparable to a 2004 third quarter net income of $6.0 million. The USOGP unit contributed $9.9 million in the nine months ended September 30, 2005.



Taxes

Three months ended Nine months ended
Consolidated September 30, September 30,
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% %
($ 000s) 2005 2004 Change 2005 2004 Change
---------------------------------------------------------------------
---------------------------------------------------------------------
Capital taxes $ 767 $ 1,202 (36) $3,677 $ 3,374 9
Current and
withholding
taxes 2,553 326 683 6,924 618 1,020
Future
income tax
expense
(recovery) 4,298 (12,991) (133) (5,534) (30,577) (82)
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$ 7,618 $(11,463) - $5,067 $(26,585) -
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Capital taxes in the third quarter totaled $0.8 million, a decrease of 36 percent below the $1.2 million recorded in the third quarter of 2004 and $3.7 million year to date compared to $3.4 million year to date for 2004. The decrease in quarter over quarter taxes reflects a large third quarter 2004 expense caused by an increase in paid-up capital in the third quarter of 2004. The increase in the year to date reflects the increase in the Saskatchewan resource surcharge that is sensitive to crude oil and natural gas prices.

The current and withholding taxes total $2.6 million in the third quarter of 2005, an increase of $2.2 million over the comparable 2004 quarter. These taxes arise from Provident's U.S. based operations and for the third quarter of 2005, represent 11 percent of USOGP EBITDA.

For the nine months ended September 30, 2005 current and withholding taxes total $6.9 million. This year-to-date amount includes $0.9 million of taxes related to 2004 operations. The reported taxes in 2005 net of the $0.9 million prior period adjustment constitute 12 percent of year-to-date USOGP EBITDA. Reported taxes for the year ended December 31, 2004 were five percent of USOGP EBITDA. Had the reported 2004 results included the $0.9 million of taxes on 2004 USOGP operations, the tax burden reported would have been 10 percent of USOGP EBITDA for the year ended December 31, 2004.

The 2005 third quarter future income tax expense of $4.3 million on third quarter income before taxes and non-controlling interests of $26.7 million as compared to the expected expense of $10.2 million primarily is a result of interest and royalty charged by the Trust to its incorporated subsidiary, Provident Energy Ltd. These amounts are deductible in computing the income of the subsidiary. The Trust is a taxable entity under Canadian income tax law and is taxable only on income that is not distributed or distributable to the unit holders. If the Trust distributes all of its taxable income to the unitholders, no provision for taxes is required by the Trust. Since inception the trust has distributed all of its taxable income to the unitholders. Recoveries of $13.0 million of future taxes in the third quarter of 2004 on losses before tax of $15.2 million, exceeds the expected recovery of $5.9 million primarily for the same reasons.

Reconciliation of non-GAAP measure

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



Three months ended Nine months ended
EBITDA Reconciliation September 30, September 30,
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(000s, except per unit data) 2005 2004 2005 2004
---------------------------------------------------------------------
EBITDA $ 94,648 $ 62,753 $245,639 $ 149,610
Adjusted for:
Interest and non-cash
expenses excluding
unrealized loss on
financial instruments (58,076) (62,162) (172,544) (145,860)
Unrealized loss on
financial instruments (9,888) (15,805) (24,259) (47,136)
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Income (loss) before
taxes and non-controlling
interests $ 26,684 $(15,214) $ 48,836 $ (43,386)
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Interest expense

Three months ended Nine months ended
Consolidated September 30, September 30,
---------------------------------------------------------------------
($000s except % %
per unit data) 2005 2004 Change 2005 2004 Change
---------------------------------------------------------------------
---------------------------------------------------------------------

Interest on
bank debt $ 1,535 $ 3,378 (55) $ 6,775 $ 8,451 (20)
Weighted
-average
interest
rate on
bank debt 3.7% 4.1% (10) 3.8% 4.2% (10)
Interest
on 10.5%
convertible
debentures(4) - 1,321 - 2,431 3,942 (38)
Interest on
8.75%
convertible
debentures 877 1,654 (47) 4,092 4,935 (17)
Interest on
8.0%
convertible
debentures (2) 830 942 (12) 2,856 942 203
Interest on 6.5%
convertible
debentures (3) 1,557 - - 3,764 - -
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Total cash
interest $ 4,799 $ 7,295 (34) $19,918 $ 18,270 9
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Weighted
average
interest
rate on
all long-term
debt 6.0% 8.9% (33) 4.8% 5.0% (4)
Non -cash
accretion
expense
- convertible
debentures 1,387 791 75 3,601 2,538 42
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Total interest
including
accretion on
convertible
debentures $ 6,186 $ 8,086 (23) $ 23,519 $20,808 13
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(1) Restated - note 2.
(2) On July 6, 2004 the Trust issued $50.0 million of unsecured
subordinated convertible debentures with an 8 percent coupon
rate maturing July 31, 2009.
(3) On March 1, 2005 the Trust issued $100.0 million of unsecured
subordinated convertible debentures with a 6.5 percent coupon
rate maturing August 31, 2012.
(4) On May 31, 2005 the Trust redeemed the 10.5 percent unsecured
convertible debentures issuing 3.5 million trust units and $3.0
million in cash.


Interest on bank debt decreased in the third quarter of 2005 compared to the third quarter in 2004 as the Trust applied the proceeds from the March 1, 2005 issue of $100 million in subordinated convertible debentures towards paying down bank debt and did not draw on its bank facilities to finance corporate acquisitions.

Cash interest expense on debentures increased for the year to date as compared to the same period in 2004 reflecting the March 1, 2005 issue of $100 million of 6.5 percent subordinated convertible debentures partly offset by the May 31 redemption of approximately $45.7 million of 10.5 percent subordinated convertible debentures. Accretion and amortization on convertible debentures has resulted from Provident adopting the revised CICA Handbook section 3860 and reclassifying the bulk of its subordinated convertible debentures to long-term debt and an additional portion to equity.

Commodity price risk management program

The Trust continues to execute 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. Our hedging strategy uses structures that provide a floor price while allowing upside participation in a rising price market.

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

Activity in the Third Quarter:

Crude oil

For the period January 1 to December 31, 2006 Provident purchased crude oil put options on 1,000 barrels per day at an average strike price of US$54.00 per barrel. Provident also entered into crude oil participating swaps for 500 barrels per day at an average floor price of US$54.50 per barrel, with an average participating percentage of 62 percent above the floor price, for the same period.

Natural Gas

For the period November 1 to December 31, 2005 Provident entered into natural gas participating swaps on 5,500 gigajoules ("gj") per day at an average floor price of $7.36 with participation percentages up to 90 percent above the floor price. For the period January 1 to December 31, 2006 Provident entered into natural gas participating swaps on an average of 17,664 gj's per day at an average floor price of Cdn$7.25 per gj, with participation percentages up to 90 percent above the floor price.

Midstream

a) Natural gas

Provident entered into the following natural gas fixed price swaps to protect margin. These contracts settle against the natural gas AECO monthly index.

- Cdn$8.84 per gj on 8,000 gj's per day of natural gas to protect margin on Ethane production for the period September 1 to September 30, 2005,

- Cdn$10.08 per gj on 4,000 gj's per day of natural gas to protect margin on Ethane production for the period October 1 to October 31, 2005, and

- Cdn$7.26 per gj on 4,661 gj's per day of natural gas purchases for the period August 1 to October 31, 2005.

b) Propane

Provident entered into the following propane fixed price swaps to protect margin. These contracts settle against the monthly calendar average for Mont Belvieu propane:

- US$0.85 per US gallon (usg) on 32,802 usg per day (Gpd) for the period August 1 to October 31, 2005,

- US$1.05 per usg on 32,413 Gpd for the period October 1 to December 31, 2005 and

- US$1.00 per usg on 58,800 Gpd for the period January 1 to March 31, 2006.

c) Condensate

Provident entered into the following WTI fixed price swaps to protect margin on condensate production. These contracts settle against the monthly calendar average for WTI.

- US$60.76 per barrel on 30,000 barrels for the month of August 2005,

- US$65.05 per barrel on 30,000 barrels for the month of September 2005, and

- US$60.50 per barrel on 319 barrels per day for the period August 1 to October 31, 2005.

The following is a summary of the net cash flow to settle commodity contracts during the third quarter of 2005 as well as for the nine months ended September 30, 2005. For comparative purposes the 2004 amounts are also summarized.

a) Crude oil

For the quarter ended September 30, 2005, Provident paid $18.9 million to settle various oil market based contracts on an aggregate volume of 0.6 million barrels. During the quarter ended September 30, 2004, Provident paid $17.6 million to settle various oil market based contracts on an aggregate volume of 0.7 million barrels.

For the nine months ended September 30, 2005, Provident paid $42.5 million to settle various oil market based contracts on an aggregate volume of 1.9 million barrels. For the comparable 2004 period, Provident paid $38.8 million to settle various oil market based contracts on aggregate volume of 2.0 million barrels.

It is estimated that if contracts in place had been settled at September 30, 2005 an opportunity cost of $28.4 million (September 30, 2004 - $51.1 million) would have been incurred.

b) Natural Gas

For the quarter ended September 30, 2005, Provident paid $0.7 million to settle various natural gas market based contracts on an aggregate volume of 1.6 million gj's. For comparison, during the quarter ended September 30, 2004, Provident paid $3.4 million to settle various natural gas market based contracts on an aggregate of 2.8 million gj's.

For the nine months ended September 30, 2005, Provident paid $1.5 million to settle various natural gas market based contracts on an aggregate volume of 4.3 million gj's. For the comparable 2004 period, Provident paid $8.4 million to settle various natural gas market based contracts on an aggregate of 9.1 million gj's.

It is estimated that if contracts in place had been settled at September 30, 2005 an opportunity cost of $17.0 million (September 30, 2004 - $3.9 million) would have been incurred.

c) Midstream

For the quarter ended September 30, 2005 Provident paid $1.1 million (2004 - $3.2 million) on Midstream margin stabilization hedging activities.
For the nine months ended September 30, 2005 Provident paid $0.6 million (2004 - $3.5 million) on Midstream margin stabilization hedging activities. It is estimated that if contracts in place had been settled at September 30, 2005 an opportunity cost of $1.8 million (September 30, 2004, opportunity gain - $0.3 millioon) would have been incurred.

d) Foreign exchange contracts

As at September 30, 2005 the estimated value of contracts in place settled at September 30 foreign exchange rates would have resulted in an opportunity gain of $0.6 million (September 30, 2004, opportunity gain - $0.6 million). The foreign exchange gains have been included in note 9 as a component of realized loss on financial derivative instruments and allocated to their respective business segments.

A summary of Provident's contracts in place at September 30, 2005 is contained in the following tables:



COGP
---------------------------------------------------------------------
2005
---------------------------------------------------------------------
Product Volume Terms Effective Period
---------------------------------------------------------------------
Light Oil (6) 2,750 Bpd US $26.07 per bbl (1) October 1
- December 31
500 Bpd Costless collar October 1


US $26.00 - $30.10 per bbl - December 31
---------------------------------------------------------------------
2006
---------------------------------------------------------------------
Light Oil (6) 750 Bpd Participating Swaps US January 1
$51.33 per bbl (63% above - December 31
floor price) (1) (3)
500 Bpd Participating Swaps US January 1
$48.00 per bbl (max to 90% - December 31
above floor price) (3)
750 Bpd Puts US $53.33 per bbl(1) January 1
- December 31
---------------------------------------------------------------------
---------------------------------------------------------------------


COGP
---------------------------------------------------------------------
2005
---------------------------------------------------------------------
Volume
(Buy)/
Product Sell Terms Effective Period
---------------------------------------------------------------------
Natural 5,000 Gjpd Participating Swaps October 1
Gas (2) Cdn $5.60 per gj (55% - October 31
above floor price) (3)
10,000 Participating Swaps Cdn October 1
$6.00 per gj (max to 73% - October 31
above floor Gjpd price)
(1) (3)
2,500 Gjpd Puts Cdn $6.50 per gj October 1
- October 31
2,000 Gjpd Participating Swaps October 1
Cdn $5.75 per gj (60% - October 31
above floor price) (3)
5,000 Gjpd Participating Swaps November 1
Cdn $6.80 per gj (64% - November 30
above floor price) (3)
10,500 Participating Swaps Cdn November 1
$7.19 per gj (max to 90% - December 31
above floor Gjpd price)(3)
---------------------------------------------------------------------
2006
---------------------------------------------------------------------
Natural 10,000 Participating Swaps Cdn January 1
Gas (2) $8.00 per gj (max to 90% - March 31
above floor Gjpd price)
(1) (3)
8,500 Participating Swaps Cdn January 1
$7.32 per gj (max to 90% - December 31
above floor Gjpd price)
(1) (3)
5,000 Participating Swaps Cdn April 1
$6.75 per gj (max to 87% - October 31
above floor Gjpd price)
(1) (3)
5,000 Participating Swap Cdn April 1
$7.00 per gj (max to 85% - December 31
above floor Gjpd price)(3)
---------------------------------------------------------------------
---------------------------------------------------------------------


---------------------------------------------------------------------
2005
---------------------------------------------------------------------
Product Terms Effective Period
---------------------------------------------------------------------
Foreign Exchange Sell US $6,500,000 @ October 1
$1.22525(1)(4) - November 30
Sell US $1,458,804 @ October 1
$1.2273 (5) - October 31
Sell US $1,480,622 @ October 1
$1.23650 (5) - October 31
---------------------------------------------------------------------
---------------------------------------------------------------------


USOGP
---------------------------------------------------------------------
2005
---------------------------------------------------------------------
Volume
(Buy)/ Remaining
Product Sell Terms Effective Period
---------------------------------------------------------------------
Light Oil (6) 1000 Bpd Participating Swaps US October 1
$45.50 per bbl (70% above - December 31
floor price) (1) (3)
500 Bpd Costless collar US October 1
$30.00 - $39.80 per bbl - December 31
500 Bpd Costless collar US October 1
$30.00 - $39.50 per bbl - December 31
500 Bpd Costless collar US October 1
$30.00 - $39.37 per bbl - December 31
500 Bpd Costless collar US October 1
$30.00 - $40.00 per bbl - December 31
750 Bpd Puts US $40.00 per bbl October 1
- December 31
---------------------------------------------------------------------
2006
---------------------------------------------------------------------
1000 Bpd Participating Swap US January 1
$47.25 per bbl (64% above - December 31
floor price) (1) (3)
1000 Bpd Puts US $53.00 per bbl(1) January 1
- December 31
---------------------------------------------------------------------
---------------------------------------------------------------------


Midstream
---------------------------------------------------------------------
2005
---------------------------------------------------------------------
Volume
(Buy)/ Remaining
Product Sell Terms Effective Period
---------------------------------------------------------------------
Ethane 4,000 Gjpd Cdn $10.08 per gj (7) October 1
- October 31
Propane 60,522 Gpd US $0.84797 per usg(1) October 1
- October 31
13,770 Gpd US $1.165 per usg October 1
- November 30
57,522 Gpd US $0.9274 per usg (1) October 1
- December 31
Condensate 759 Bpd US $57.31 per bbl(1)(6) October 1
- October 31
Natural (8,661) Gjpd Cdn $7.39 per gi (1) October 1
Gas (2) - October 31
---------------------------------------------------------------------
2006
---------------------------------------------------------------------
Propane 58,800 Gpd US $0.9981 per usg(1) January 1
- March 31
---------------------------------------------------------------------
---------------------------------------------------------------------
(1) Represents a number of transactions entered into over an extended
period of time.
(2) Natural gas contracts are settled against AECO monthly index.
(3) Provides a floor price while allowing percentage participation
above strike price.
(4) US dollar Cashflow
(5) Foreign exchange contracts to hedge underlying exchange rate on
Cdn cashflow.
(6) Settled against monthly calendar average for WTI.
(7) Settled against AECO natural gas monthly index.


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. Goodwill arose from the acquisitions of Richland Petroleum Corporation, $13.3 million, and Meota Resources Corp., $89.1 million in 2002 and from Olympia Energy Inc., $106.5 million, and Viracocha Energy Inc., $122.0 million in 2004.

Goodwill is assessed for impairment at least annually. If impairment exists, it is charged to income in the period in which the impairment occurs. Provident engaged an independent accounting firm to assist in performing an impairment test at year end 2004. The impairment test included, among other variables, a comparison of the net book value of the Trust's assets to the market value of the Trust's equity. Goodwill is not amortized.



Liquidity and capital resources


Consolidated
---------------------------------------------------------------------
($ 000s) September 30, 2005 December 31, 2004 % Change
---------------------------------------------------------------------

Long-term debt -
revolving term
credit facility $ 182,171 $ 262,750 (31)
Long-term debt -
convertible debentures $159,079 $169,456 (6)
Working capital deficit 29,460 38,677 (24)
---------------------------------------------------------------------
Net debt 370,710 470,883 (21)
---------------------------------------------------------------------
---------------------------------------------------------------------

Equity (at book value) 1,136,521 1,009,048 13
---------------------------------------------------------------------
Total capitalization at
book value $ 1,507,231 $ 1,479,931 2
---------------------------------------------------------------------
---------------------------------------------------------------------

Net debt as a percentage of
total book value
capitalization 25% 32% (22)
---------------------------------------------------------------------
---------------------------------------------------------------------


Provident operates three business units with similar but not identical monthly cash settlement cycles. 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 cash flow from operations, external lines of credit and access to equity markets to fund capital programs and acquisitions.

Long-term debt and working capital

As at September 30, 2005 Provident had drawn $182.2 million or 32 percent of its term credit facility of $572.5 million as compared to $262.8 million or 64 percent drawn on its $410.0 million term credit facility as at December 31, 2004. The decrease in the level of bank debt was due primarily to the increase in convertible debentures. On March 1, 2005 the Trust issued $100.0 million ($95.8 million net of issue costs) of 7.5 year unsecured convertible debentures with a 6.5 percent coupon rate maturing August 31, 2012. Convertible debentures are classified as long-term debt, excluding a minor equity component.

At September 30, 2005 Provident had letters of credit guaranteeing Provident's performance under certain commercial and other contracts that totaled $27.9 million, increasing bank line utilization to 37 percent. The guarantees totaled $31.0 million at December 31, 2004.

On July 22, 2005 the Trust expanded its existing term credit facility to $572.5 million from $410.0 million. The new facility is comprised of $450.0 million related to its Canadian assets and $122.5 million (US $100.0 million) of lending capacity for its US assets. The facilities are separate and each supported by separate syndicates of banks. The terms of the new banking agreement are substantially unchanged from the previous agreement.

Provident's working capital increased by $9.2 million as at September 30, 2005
relative to December 31, 2004. Of this amount $32.9 million was due to an increase in accounts receivable, a $18.0 million increase in inventory; partially offset by a $20.3 million increase in accounts payable and a $21.4 million increase in financial derivative instruments and other.

Third quarter cash flow in 2005 was $86.3 million. The ratio of debt to annualized third quarter cash flow improved to one to one, as compared to third quarter 2004 debt to annualized cash flow of 1.5 to one.

Trust units and exchangeable shares

On March 1, 2005 the Trust issued 8.4 million units at a price of $12.00 per unit for proceeds after underwriting fees of $95.6 million, concurrent with the issue of convertible debentures noted above. Proceeds from the issue were used to pay down Provident's bank debt and to finance the Nautilus Resources, LLC acquisition and throughout 2005 will be used to finance the company's 2005 capital budget. In the third quarter of 2005, the Trust also issued 0.3 million units (conversion amount $3.3 million) on conversion of exchangeable shares to units. For the quarter ended September 30, 2005 the Trust issued 4.3 million units on conversion of convertible debentures (2004 - 0.3 million units). An additional 0.2 million units pursuant to the stock option plan were issued for the quarter ended September 30, 2005 (2004 - 0.1 million units). Details of these issues are outlined in the notes to the financial statements. Under Provident's Premium Distribution, Distribution Reinvestment (DRIP) and Optional Unit Purchase Plan program 0.3 million units were elected in the third quarter and will be issued or are to be issued representing proceeds of $4.3 million (2004 - 0.6 million units for proceeds of $6.0 million).

At September 30, 2005 management and directors held approximately 1.5 percent of the outstanding units and exchangeable shares.

Non-controlling interest

(i) USOGP operations

A non-controlling interest arose from Provident's June 15, 2004 acquisition of 92 percent of BreitBurn Energy of Los Angeles, California. The founders of BreitBurn Energy beneficially own the non-controlling interest, which share in earnings or losses of BreitBurn. The non-controlling interest is reduced by distributions to its holders.



Non-controlling interest Three months ended Nine months ended
- USOGP September 30, September 30,
---------------------------------------------------------------------
($ 000s) 2005 2004 2005
---------------------------------------------------------------------
Non-controlling interest,
beginning of period $ 13,069 $ 13,820 $ 13,649
Net income attributable
to non-controlling interest 527 566 926
Distributions to
non-controlling interest (718) (563) (1,697)
---------------------------------------------------------------------
Non-controlling interest,
end of period $ 12,878 $ 13,823 $ 12,878
---------------------------------------------------------------------
Accumulated income
attributable to
non-controlling interest $ 1,849 $ 622 $ 1,849
---------------------------------------------------------------------
---------------------------------------------------------------------


The non-controlling interest percentage as at September 30, 2005 was approximately 4.4 percent of BreitBurn, which is unchanged from the position as at June 30, 2005, and was 7.2 percent as at September 30, 2004.

(ii) Exchangeable shares

As at June 30, 2005 the Trust retroactively applied EIC 151 "Exchangeable Securities Issued by a Subsidiary of an Income Trust". The non-controlling interest on the consolidated balance sheet consists of the fair value of the exchangeable shares upon issuance plus the accumulated earnings attributable to the non-controlling interest. The net income attributable to the non-controlling interest on the consolidated statement of operations represents the cumulative share of net income attributable to the non-controlling interest based on the trust units issuable for exchangeable shares in proportion to total trust units issued and issuable at each period end during the period.

Following is a summary of the non-controlling interest - exchangeable shares for the quarters and nine month periods ended September 30, 2005 and 2004:



Non-controlling interest Three months ended Nine months ended
- Exchangeable shares September 30, September 30,
---------------------------------------------------------------------
($ 000s) 2005 2004(1) 2005 2004(1)
---------------------------------------------------------------------
Non-controlling interest,
beginning of period $ 12,979 $ 45,877 $ 35,921 $ 20,542
Exchangeable shares issued - - - 30,264
Reduction of book value for
conversion to trust units (3,294) (9,976) (26,501) (14,593)
Net income attributable
to non-controlling interest 153 (96) 418 (408)
---------------------------------------------------------------------
Non-controlling interest,
end of period $ 9,838 $ 35,805 $ 9,838 $ 35,805
---------------------------------------------------------------------
Accumulated income
attributable to
non-controlling interest $ 1,900 $ 616 $ 1,900 $ 616
---------------------------------------------------------------------
---------------------------------------------------------------------
(1) Restated - note 2.


The non-controlling interest percentage as at September 30, 2005 was 0.7 percent that is a decrease from the retroactively applied non-controlling interest percentage as at December 31, 2004 of 2.2 percent. The decrease is attributable to the conversion of exchangeable shares for trust units.



Capital expenditures and funding

Three months ended Nine months ended
Consolidated September 30, September 30,
---------------------------------------------------------------------
% %
($ 000s) 2005 2004 Change 2005 2004 Change
---------------------------------------------------------------------
---------------------------------------------------------------------

Capital Expenditures
Capital
expenditures
and
reclamation
fund
contributions
$(41,478) $(27,553) 51 $(109,098)$ (51,846) 110
Property
acquisitions (680) (3,991) (83) (680) (8,709) (92)
Corporate
acquisitions - (1,300) - (91,420) (173,657) (47)
Property
dispositions 44,639 - - 44,639 7,114 527
---------------------------------------------------------------------
Net capital
expenditures $ 2,481 $(32,844) (108)$(156,559)$(227,098) (31)
---------------------------------------------------------------------

Funded By
Cash flow net
of declared
distributions
to unitholders
and non-
controlling
interest $ 23,165 $ 7,587 205 $ 42,022 $ 14,311 194
Bridge
Financing - - - - 158,184 -
Repayment
of bridge
financing - (158,184) - - (158,184) -
Issue of
convertible
debentures,
net of cost - 48,000 - 95,759 48,000 99
Redemption of
convertible
debentures - - - (2,997) - -
Issue of trust
units, net
of cost;
excluding
DRIP 2,212 130,114 (98) 118,218 180,751 (35)
DRIP proceeds 4,286 6,028 (29) 13,593 14,361 (5)
Change in
working
capital,
including cash,
payment of
financial
derivative
instruments,
sale of
marketing
contracts
and
investments (5,669) (11,519) (51) (31,304) (14,100) 122
Increase
(decrease)
in long-term
debt (26,475) 10,818 (345) (78,732) (16,225) 385
---------------------------------------------------------------------
Net capital
expenditure
funding $ (2,481) $ 32,844 (108)$ 156,559 $ 227,098 (31)
---------------------------------------------------------------------
---------------------------------------------------------------------


For the comparable quarters Provident has funded its net capital expenditures with cash flow, debt, working capital and equity issued from treasury through public offerings and the Premium DRIP program.

Acquisition

On March 2, 2005 the Trust, through its U.S. subsidiary, acquired Nautilus Resources, LLC for $90.2 million. At that time $8.1 million was paid to fully satisfy outstanding financial derivative instruments acquired through the Nautilus acquisition. This acquisition was financed through cash mainly raised through a trust unit issue of $95.6 million net of issue costs.

Disposition

On September 29, 2005, Provident, through two wholly-owned Canadian subsidiaries, disposed of various non-core properties and land in Saskatchewan and Alberta for cash proceeds, net of disposition costs, of $44.6 million. The disposed properties averaged approximately 2,100 boed for the period July 1, 2005 to September 28, 2005 and had proved plus probable reserves of 6,397 mboe. Approximately 87,850 net acres of land were also included in the disposition. In addition, $13.6 million was removed from the asset retirement obligation, which represented the discounted future cash flows to settle the asset retirement obligations related to these properties. As a result of the disposition, Provident expects COGP production for the full year of 2005 to average between 26,000 and 27,000 boed. The net cash proceeds will mainly be used to fund Provident's ongoing budgeted capital program and to service debt.



Asset retirement obligation

Three months ended Nine months ended
Consolidated September 30, September 30,
---------------------------------------------------------------------
% %
($ 000s) 2005 2004 Change 2005 2004 Change
---------------------------------------------------------------------

Carrying amount,
beginning
of period $ 43,209 $ 43,133 - $ 40,506 $ 33,182 22
Oil and gas
corporate
acquisitions - - - 1,557 - -

Increase in
liabilities
incurred
during the
period 767 680 13 1,219 12,087 (90)
Settlement of
liabilities
during the
period (700) (1,150) 39 (1,695) (3,822) 56
Decrease in
liabilities
due to
disposition (13,612) - - (13,612) - -
Accretion of
liability 803 636 26 2,492 1,852 35
---------------------------------------------------------------------
Carrying
amount, end
of period $ 30,467 $ 43,299 (30) $ 30,467 $ 43,299 (30)
---------------------------------------------------------------------
---------------------------------------------------------------------


The asset retirement obligation (ARO) as at September 30, 2005 is $30.5 million. The ARO before the non-core properties disposition of $44.1 million was comparable to the position as at September 30, 2004 as accretion on the historical balance was partially offset by ongoing abandonment and reclamation expenditures.

The Trust's asset retirement obligation is based on the Trust's net ownership in wells, facilities and 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.

As a result of the disposition, the total undiscounted amount of future cash flows required to settle asset retirement obligations related to oil and gas operations is estimated to be $110.4 million as at September 30, 2005. Payments to settle oil and gas asset retirement obligations occur over the operating lives of the assets estimated to be from two to 55 years.

The total undiscounted amount of future cash flows required to settle the Midstream asset retirement obligations is estimated to be $26.1 million. The estimated costs include such activities as dismantling, demolition and disposal of the facilities as well as remediation and restoration of the surface land. Payments to settle the Midstream asset retirement obligations are expected to occur subsequent to the closure of the facilities and related assets. Settlement from the balance sheet date of these obligations is expected to occur over 30 to 35 years.

Non-cash general and administrative

Non-cash general and administrative costs include expenses or recoveries associated with Provident's unit option plan and unit appreciation plan. Provident accounts for the unit option plan using the fair value of the option at the time of issue and for the unit appreciation plan based on the market price of the Trust units. Compensation expense associated with the options is deferred and recognized in earnings over the vesting period of the options. The Trust recorded an expense of $0.3 million for the quarter ended September 30, 2005 (2004 - $1.9 million). For the nine months ended September 30, 2005 the Trust recorded an expense of $0.8 million (2004-$1.2 million). Compensation expense associated with the unit appreciation plan is expensed over the life of the unit appreciation rights. The Trust recorded an expense of $2.2 million for the quarter ended September 30, 2005 (2004 - nil). For the nine months ended September 30, 2005 the Trust recorded an expense of $4.1 million (2004 - nil).

Restricted/Performance Units

In October 2005 the board of directors approved a program whereby certain employees of the Trust's Canadian subsidiaries will be granted restricted trust units (RTU's) and/or performance trust units (PTU's), both of which entitle the employee to receive cash compensation in relation to the value of a specified number of underlying notional trust units. This plan is effective for 2005 and subsequent years. The Trust will administer existing unit option agreements but will not issue further options under its unit option program. RTU's vest evenly over a period of three years commencing one year after grant and are awarded based on an assessment of the employee's future potential to the company. Payments are made on the anniversary dates of the RTU to the employees entitled to receive them on the basis of a cash payment equal to the value of the underlying notional units. PTU's vest three years from the date of grant and can be increased to a maximum of double the PTU's granted or a minimum of nil PTU's depending on the Trust's performance vis-a-vis other trusts' performance based on total return. PTU's entitle employees to receive cash payments equal to the market price of the underlying notional Trust's Units.

The estimated fair value associated with the RTU's and PTU's is expensed in the statement of income over the vesting period. During the nine months ended September 30, 2005, the Trust recorded compensation costs of $1.5 million with respect to the expected issue of RTU's and PTU's (2004 - nil).

Subsequent event

On October 27, 2005, the Trust announced that it has agreed to acquire the natural gas liquids (NGL) business of EnCana Corporation, for a purchase price of approximately $697 million, plus working capital and other adjustments, estimated to be $80 million. The acquired business includes interests in an interconnected set of NGL extraction, transportation, storage, fractionation and distribution facilities, with current throughput of approximately 25,000 barrels per day of ethane and approximately 13,500 barrels per day of propane-plus. Also included is NGL marketing company Kinetic Resources.

In conjunction with the acquisition, Provident has entered into an underwriter's agreement and issued a prospectus offering to issue 21.8 million subscription receipts. Each subscription receipt is offered at a price of $12.60 and entitles the holder to receive one trust unit upon completion of the acquisition of the NGL business. Provident has also granted the underwriters an option to purchase up to an additional 3.2 million subscription receipts during the offering. In addition, Provident will issue $150.0 million principal amount of 6.50 percent convertible extendible unsecured subordinated debentures with an expected maturity date of April 30, 2011. The remainder of the purchase price will be financed with bank debt. Concurrent with this announcement, Provident also increased its Canadian dollar revolving term credit facility by $300 million to a total of $750 million, with terms similar to the existing facility.

To ensure sufficient funds are available to complete the acquisition, Provident has obtained a bridge financing facility amounting to $474 million. The bridge facility will be utilized to complete the acquisition only in the event the subscription receipt and convertible debenture offerings are not completed.

The transaction and securities offerings are expected to close in the fourth quarter of 2005.



COGP segment review

Crude oil and liquids price
The following prices are net of transportation expense.

Three months ended Nine months ended
COGP September 30, September 30,
---------------------------------------------------------------------
% %
($ per boe) 2005 2004 Change 2005 2004 Change
---------------------------------------------------------------------

Realized pricing before hedging
Light/medium
oil $ 61.36 $ 46.68 31 $ 51.97 $ 43.12 21
Heavy oil $ 46.74 $ 34.23 37 $ 31.95 $ 29.84 7
Natural gas
liquids $ 54.40 $ 40.88 33 $ 48.98 $ 39.75 23
---------------------------------------------------------------------
Crude oil and
natural gas
liquids $ 56.23 $ 41.41 36 $ 45.21 $ 37.17 22
---------------------------------------------------------------------
---------------------------------------------------------------------


Three months ended Nine months ended
COGP September 30, September 30,
---------------------------------------------------------------------
% %
($ per bbl) 2005 2004 Change 2005 2004 Change
---------------------------------------------------------------------

Oil per barrel
WTI (US$) $ 63.19 $ 43.85 44 $ 55.40 $ 39.14 42
Exchange rate
(from US$
to Cdn$) $ 1.20 $ 1.31 (8) $ 1.22 $ 1.33 (8)
WTI expressed
in Cdn$ $ 75.83 $ 57.44 32 $ 67.59 $ 52.06 30
---------------------------------------------------------------------
---------------------------------------------------------------------


In the third quarter of 2005 Provident's realized oil and natural gas liquids price, prior to the impact of hedging, increased by 36 percent to $56.23 per barrel compared to $41.41 in the third quarter of 2004. For the nine months ended September 30, 2005 the realized oil and natural gas liquids price was $45.21 per barrel, 22 percent above the $37.17 in the comparable period of 2004. The 2005 increase related to a higher US$ WTI crude oil price partially offset by a stronger Canadian dollar and wider differentials on heavy oil pricing relative to WTI. Quarter over quarter, Provident reduced its volume of conventional heavy oil as a percentage of total mix from 21 percent in 2004 to 16 percent in 2005. This is a result of the Viracocha and Olympia acquisitions of light/medium oil and natural gas and natural production declines in Provident's heavy oil areas.



Natural gas price

The following prices are net of transportation expense.

Three months ended Nine months ended
COGP September 30, September 30,
---------------------------------------------------------------------
% %
($ per mcf) 2005 2004 Change 2005 2004 Change
---------------------------------------------------------------------
AECO monthly
index (Cdn$)
per mcf $ 9.28 $ 6.67 39 $ 7.84 $ 6.69 17
Corporate
natural gas
price per
mcf before
hedging
(Cdn$) $ 8.44 $ 6.47 30 $ 7.48 $ 6.61 13
---------------------------------------------------------------------
---------------------------------------------------------------------


Provident's third quarter 2005 realized natural gas price, excluding hedges, increased 30 percent as compared to the third quarter of 2004, slightly less than the increase in the benchmark AECO index price of 39 percent. For the nine months ended September 30, 2005 the realized natural gas price, excluding hedges, increased 13 percent to $7.48 per mcf from $6.61 in the same period of 2004.



Production

Three months ended Nine months ended
COGP September 30, September 30,
---------------------------------------------------------------------
% %
2005 2004 Change 2005 2004 Change
---------------------------------------------------------------------

Daily production
Crude oil
- Light/Medium
(bpd) 8,088 9,387 (14) 8,456 7,564 12
- Heavy (bpd) 4,075 6,770 (40) 4,750 6,632 (28)
Natural gas
liquids (bpd) 1,499 1,782 (16) 1,557 1,393 12
Natural gas
(mcfd) 73,695 87,078 (15) 76,206 72,941 4
---------------------------------------------------------------------
Oil equivalent
(boed) (1) 25,945 32,453 (20) 27,464 27,746 (1)
---------------------------------------------------------------------
---------------------------------------------------------------------
(1) Provident reports equivalent production converting natural gas
to oil on a 6:1 basis.


Production decreased 20 percent to 25,945 boed during the third quarter of 2005 as compared to 32,453 boed in 2004. For the nine months ended September 30, 2005 production decreased one percent to 27,464 boed as compared to 27,746 boed for the comparable period of 2004. The decrease reflects the natural production declines including higher than expected declines in heavy oil partially offset by drilling and optimization activities. Provident expects the higher declines in heavy oil to improve in future periods. The non-core properties disposition did not have a significant impact on the third quarter and nine months ended September 30, 2005 production. 2004 comparative amounts include the acquisition of Olympia and Viracocha to the COGP production base before natural production declines.

Production for the third quarter of 2005 was weighted 47 percent natural gas, 16 percent heavy oil, and 37 percent medium/light crude oil and natural gas liquids. Production over the nine months ended September 30, 2005 was weighted 46 percent natural gas, 17 percent heavy oil and 37 percent medium/light crude oil and natural gas liquids. Provident mitigates its production risk by not having any single property providing greater than 10 percent of its daily production.

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



COGP
---------------------------------------------------------------------
Three months
ended West
September Lloyd- Central Southern Southern
30, 2005 minister Alberta Alberta Saskatchewan Other Total
---------------------------------------------------------------------

Daily production
Crude oil
- Light/
Medium (bpd) 1,508 1,297 2,599 2,683 1 8,088
- Heavy (bpd) 4,075 - - - - 4,075
Natural gas
liquids (bpd) 13 1,369 116 1 - 1,499
Natural gas
(mcfd) 2,422 39,546 25,211 6,505 11 73,695
---------------------------------------------------------------------
Oil equivalent
(boed) (1) 6,000 9,257 6,917 3,768 3 25,945
---------------------------------------------------------------------
---------------------------------------------------------------------


COGP
---------------------------------------------------------------------
Three months
ended West
September Lloyd- Central Southern Southern
30, 2004 minister Alberta Alberta Saskatchewan Other Total
---------------------------------------------------------------------

Daily production
Crude oil
- Light/
Medium (bpd) 1,853 1,568 3,080 2,883 3 9,387
- Heavy (bpd) 6,770 - - - - 6,770
Natural gas
liquids (bpd) 8 1,630 139 3 2 1,782
Natural gas
(mcfd) 5,320 48,375 30,221 3,139 23 87,078
---------------------------------------------------------------------
Oil equivalent
(boed) (1) 9,524 11,261 8,252 3,409 7 32,453
---------------------------------------------------------------------
---------------------------------------------------------------------
(1) Provident reports equivalent production converting natural gas to
oil on a 6:1 basis.



COGP
---------------------------------------------------------------------
Nine months
ended West
September Lloyd- Central Southern Southern
30, 2005 minister Alberta Alberta Saskatchewan Other Total
---------------------------------------------------------------------

Daily production
Crude oil
- Light/
Medium (bpd) 1,560 1,382 2,779 2,726 9 8,456
- Heavy (bpd) 4,750 - - - - 4,750
Natural gas
liquids (bpd) 15 1,402 139 1 - 1,557
Natural gas
(mcfd) 2,223 40,823 27,566 5,569 25 76,206
---------------------------------------------------------------------
Oil equivalent
(boed) (1) 6,695 9,588 7,513 3,655 13 27,464
---------------------------------------------------------------------
---------------------------------------------------------------------


COGP
---------------------------------------------------------------------
Nine months
ended West
September Lloyd- Central Southern Southern
30, 2004 minister Alberta Alberta Saskatchewan Other Total
---------------------------------------------------------------------

Daily production
Crude oil
- Light/
Medium (bpd) 963 1,342 2,419 2,837 3 7,564
- Heavy (bpd) 6,632 - - - - 6,632
Natural gas
liquids (bpd) 11 1,262 115 3 2 1,393
Natural gas
(mcfd) 3,479 43,430 23,189 2,799 44 72,941
---------------------------------------------------------------------
Oil equivalent
(boed) (1) 8,187 9,843 6,399 3,306 11 27,746
---------------------------------------------------------------------
---------------------------------------------------------------------
(1) Provident reports equivalent production converting natural gas to
oil on a 6:1 basis.


Internal development activities included 17.2 net drills during the quarter ended September 30, 2005. Provident's most active area, southern Saskatchewan realized 14.6 net drills. The focus of southern Saskatchewan is a shallow gas-drilling program that will realize production and reserve adds for several years. Although continued poor weather conditions have delayed tie-in operations at the beginning of the third quarter of 2005, Provident continues to bring these wells on production. Provident's other areas remain active with additional activity in Lloydminster where Provident is drilling low risk heavy oil wells and also in southern Alberta where Provident is actively drilling shallow gas wells. In West Central Alberta, Provident continues with its strategy of farming out high risk exploration land to fully optimize its high risk exploration land.

As a result of the non-core property disposition and normal underlying decline rates, Provident expects COGP production for the full year of 2005 to decrease to an average between 26,000 boed and 27,000 boed.



Revenue and royalties

Three months ended Nine months ended
Consolidated September 30, September 30,
---------------------------------------------------------------------
($000s except % %
per boe data) 2005 2004 Change 2005 2004 Change
---------------------------------------------------------------------
---------------------------------------------------------------------

Oil

Revenue $ 63,178 $ 61,585 3 $161,407 $144,084 12
Realized loss
on non-hedging
derivative
instruments (13,049) (17,312) (25) (31,049) (38,486) (19)
Royalties
(net of ARTC) (11,911) (12,171) (2) (31,097) (28,655) 9
---------------------------------------------------------------------
Net revenue $ 38,218 $ 32,102 19 $ 99,261 $ 76,943 29
---------------------------------------------------------------------
---------------------------------------------------------------------
Net revenue
(per barrel) $ 34.15 $ 21.60 58 $ 27.53 $ 19.78 39
Royalties as
a percentage
of revenue 18.9% 19.8% 19.3% 19.9%
---------------------------------------------------------------------

Natural gas

Revenue $ 57,223 $ 51,817 10 $155,571 $132,067 18
Realized loss
on non-hedging
derivative
instruments (2,792) (3,333) (16) (4,087) (8,368) (51)
Royalties
(net of ARTC) (11,743) (13,414) (12) (32,982) (29,706) 11
---------------------------------------------------------------------
Net revenue $ 42,688 $ 35,070 22 $118,502 $ 93,993 26
---------------------------------------------------------------------
---------------------------------------------------------------------

Net revenue
(per mcf) $ 6.30 $ 4.38 44 $ 5.70 $ 4.70 21
Royalties as
a percentage
of revenue 20.5% 25.9% 21.2% 22.5%
---------------------------------------------------------------------

Natural gas liquids

Revenue $ 7,502 $ 6,701 12 $ 20,820 $ 15,172 37
Royalties (1,780) (1,666) 7 (4,839) (4,028) 20
---------------------------------------------------------------------
Net revenue $ 5,722 $ 5,035 14 $ 15,981 $ 11,144 43
---------------------------------------------------------------------
---------------------------------------------------------------------
Net revenue
(per barrel) $ 41.49 $ 30.71 35 $ 37.60 $ 29.20 29
Royalties as
a percentage
of revenue 23.7% 24.9% 23.2% 26.5%
---------------------------------------------------------------------

Total

Revenue $127,903 $120,103 6 $337,798 $291,323 16
Realized loss
on non-hedging
derivative
instruments (15,841) (20,645) (23) (35,135) (46,854) (25)
Royalties
(net of ARTC) (25,434) (27,251) (7) (68,918) (62,389) 10
---------------------------------------------------------------------
Net revenue $ 86,628 $ 72,207 20 $233,745 $182,080 28
---------------------------------------------------------------------
---------------------------------------------------------------------
Net revenue
per boe $ 36.29 $ 24.18 50 $ 31.17 $ 23.95 30
Royalties as
a percentage
of revenue 19.9% 22.7% 20.4% 21.4%
---------------------------------------------------------------------
---------------------------------------------------------------------
Note: the above figures are presented net of transportation expenses.


Quarter over quarter, 2005 COGP production revenue was $127.9 million, an increase of six percent from $120.1 million in 2004. The slight increase in revenue is a result of a 33 percent increase in Provident's realized crude oil, natural gas liquids and natural gas prices offset by the natural production declines. Royalties, which are price sensitive, decreased as a percentage of revenue to 20 percent in the third quarter of 2005 from 23 percent for the comparable quarter in 2004. The preceding factors, as well as the opportunity cost of hedging activities, account for net revenue of $86.6 million in the third quarter of 2005, 20 percent above the $72.2 million recorded in the third quarter of 2004. For the nine months ended September 30, 2005 net revenue was $233.7 million, 28 percent above the $182.1 million recorded in the same period of 2004.



Production expenses

Three months ended Nine months ended
COGP September 30, September 30,
---------------------------------------------------------------------
($000s except % %
per boe data) 2005 2004 Change 2005 2004 Change
---------------------------------------------------------------------
---------------------------------------------------------------------

Production
expenses $ 23,949 $ 27,010 (11) $ 71,841 $ 63,899 12
Production
expenses
(per boe) $ 10.03 $ 9.05 11 $ 9.58 $ 8.41 14
---------------------------------------------------------------------
---------------------------------------------------------------------


Third quarter 2005 production expenses decreased 11 percent to $23.9 million from $27.0 million in the comparable 2004 quarter due to lower production volumes. For the nine months ended September 30, 2005 production expenses increased 12 percent to $71.8 million from $63.9 million in the comparable 2004 period. The increase coincides with the equivalent increase in production volumes as a result of the Olympia and Viracocha acquisitions. However, on a boe basis quarter-over-quarter production expenses have risen to $10.03 per boe, a 12 percent increase compared to $9.05 per boe in the comparable 2004 quarter. Operating expenses increased in a number of categories including well servicing, maintenance, fluid hauling, and power and fuel. Poor weather conditions experienced in the 2005 second quarter which delayed well servicing and maintenance costs into the third quarter of 2005 combined with the natural production declines resulted in higher operating costs per boe. In addition, cost increases in power and fuel, chemicals and well servicing occurred due to higher commodity prices and labour costs.

Based on the current high commodity price environment and increased levels of activity, Provident expects Canadian operating costs to average $9.50 per boe to $9.90 per boe for 2005. Commodity prices affect the demand for services. If commodity prices increase, Provident expects the price of services and labour to increase.



Operating netback

Three months ended Nine months ended
COGP September 30, September 30,
---------------------------------------------------------------------
% %
($ per boe) 2005 2004 Change 2005 2004 Change
---------------------------------------------------------------------
---------------------------------------------------------------------

COGP oil equivalent netback per boe

Gross
production
revenue $ 53.59 $ 40.22 33 $ 45.05 $ 38.32 18
Royalties
(net of ARTC) (10.66) (9.13) 17 (9.19) (8.21) 12
Operating
costs (10.03) (9.05) 11 (9.58) (8.41) 14
---------------------------------------------------------------------
Field
operating
netback $ 32.90 $ 22.04 49 $ 26.28 $ 21.70 21
---------------------------------------------------------------------
---------------------------------------------------------------------

Realized loss
on cash
hedging (6.64) (6.91) (4) (4.69) (6.16) (24)
---------------------------------------------------------------------
Operating
netback
after hedging $ 26.26 $ 15.13 74 $ 21.59 $ 15.54 39
---------------------------------------------------------------------
---------------------------------------------------------------------


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

Third quarter 2005 field operating netback of $32.90 per boe was 49 percent above the $22.04 per boe in the comparable quarter in 2004. Year to date field operating netback at $26.28 per boe was 21 percent above the same period in 2004. The increased field operating netback in the third quarter and year to date in 2005 reflects a higher WTI crude oil benchmark and a significant shift in Provident's production mix to include a greater weighting towards natural gas and lighter grades of crude oil partially offset by wider differentials and increased operating costs. Operating netbacks after hedging increased by 74 percent to $26.26 from $15.13 for the quarter, and by 39 percent to $21.59 from $15.54 year to date reflecting the third quarter opportunity cost due to hedging of $6.64 per boe compared to $6.91 in the comparable quarter in 2004. For the nine months ended September 30, 2005 opportunity costs due to hedging was $4.69 per boe (2004 comparable period was $6.16 per boe).

Netbacks by product for crude oil, natural gas liquids and natural gas are as follows:



Three months ended Nine months ended
COGP September 30, September 30,
---------------------------------------------------------------------
% %
($ per bbl) 2005 2004 Change 2005 2004 Change
---------------------------------------------------------------------
---------------------------------------------------------------------

COGP crude oil and NGL's netback per bbl

Gross
production
revenue $ 56.23 $ 41.38 36 $ 45.21 $ 37.28 21
Royalties
(net of ARTC) (10.89) (8.38) 30 (8.92) (7.65) 17
Operating
costs (15.72) (10.42) 51 (11.97) (9.18) 30
---------------------------------------------------------------------
Field
operating
netback 29.62 22.58 31 24.32 20.45 19
---------------------------------------------------------------------
---------------------------------------------------------------------

Realized loss
on cash
hedging (10.38) (10.49) (1) (7.70) (9.01) (15)
---------------------------------------------------------------------
Operating
netback
after hedging $ 19.24 $ 12.09 59 $ 16.62 $ 11.44 45
---------------------------------------------------------------------
---------------------------------------------------------------------


Three months ended Nine months ended
COGP September 30, September 30,
---------------------------------------------------------------------
% %
($ per mcf) 2005 2004 Change 2005 2004 Change
---------------------------------------------------------------------
---------------------------------------------------------------------

COGP natural gas netback per mcf

Gross
production
revenue $ 8.44 $ 6.47 30 $ 7.48 $ 6.61 13
Royalties
(net of ARTC) (1.73) (1.67) 4 (1.59) (1.49) 7
Operating costs (0.62) (1.23) (50) (1.13) (1.24) (9)
---------------------------------------------------------------------
Field
operating
netback 6.09 3.57 71 4.76 3.88 23
---------------------------------------------------------------------
---------------------------------------------------------------------

Realized loss
on cash
hedging (0.41) (0.42) (2) (0.20) (0.42) (52)
---------------------------------------------------------------------
Operating
netback
after hedging $ 5.68 $ 3.15 80 $ 4.56 $ 3.46 32
---------------------------------------------------------------------
---------------------------------------------------------------------


General and administrative

The following table does not incorporate the COGP portion of non-cash general and administrative expenses associated with Provident's unit option plan. Third quarter non-cash general and administrative expenses for COGP totaled $0.3 million for the 5.6 million options granted on or after January 1, 2003 compared to $1.9 million in the comparable period. For the nine months ended September 30, 2005 the non-cash and general and administrative expenses for COGP totaled $0.8 million compared to $1.2 million in the same period of 2004.



Three months ended Nine months ended
COGP September 30, September 30,
---------------------------------------------------------------------
($000s, except % %
per boe data) 2005 2004 Change 2005 2004 Change
---------------------------------------------------------------------

Cash general and
administrative $5,377 $ 4,277 26 $ 14,825 $ 12,521 18
Cash general and
administrative
per boe $ 2.25 $ 1.43 57 $ 1.98 $ 1.65 20
---------------------------------------------------------------------
---------------------------------------------------------------------


Cash general and administrative expenses for COGP in the third quarter increased 26 percent to $5.4 million from $4.3 million in the 2004 comparable quarter. On a boe basis the cash general and administrative expenses in the third quarter 2005 increased 57 percent to $2.25 from $1.43 in the third quarter of 2004. On a year to date basis, the cash general and administrative charge was $1.98 per boe, compared to $1.65 per boe in the comparable period in 2004.

COGP operations are capable of absorbing additional production, particularly in existing core areas, with little impact on general and administrative expenses. 2005 costs per boe are forecast to increase as a result of further increases in costs associated with compliance (including costs associated with the implementation of procedures and documentation to be in compliance with the U.S. Sarbanes-Oxley Act) and a more competitive landscape impacting the cost of hiring and compensating employees.



Capital expenditures

Three months ended Nine months ended
COGP September 30, September 30,
---------------------------------------------------------------------
($ 000s) 2005 2004 2005 2004
---------------------------------------------------------------------


Capital expenditures
Lloydminster $ 3,405 $ 4,205 $ 7,368 $ 5,416
West central and southern
Alberta 11,641 8,099 24,768 15,886
Southeast and southwest
Saskatchewan 12,840 5,511 29,712 17,609
Office and other 570 400 1,880 945
---------------------------------------------------------------------
Total additions $ 28,456 $ 18,215 $ 63,728 $ 39,856
---------------------------------------------------------------------
---------------------------------------------------------------------
Property acquisitions 680 742 680 5,460
Property dispositions $ 44,639 $ - $ 44,639 $ 7,114
---------------------------------------------------------------------
---------------------------------------------------------------------


In the third quarter of 2005, Provident's COGP business unit spent $3.4 million in the Lloydminster area primarily on drilling ($2.6 million) and facility work ($0.8 million). In West central Alberta $2.7 million was spent largely on non-operated drilling ($1.9 million) and facility work ($0.8 million). In southern Alberta $8.9 million was spent on drilling activities and recompletions ($3.9 million), facility upgrades ($4.4 million) and seismic and mineral rights acquisitions ($0.6 million). Provident spent $12.8 million in the southeast and southwest Saskatchewan core areas on acquiring mineral rights for future development ($6.3 million), drilling for shallow gas and recompletions ($5.2 million), and facility work ($1.3 million) and office and other items accounted for $0.6 million of capital.

In the first nine months of 2005 asset dispositions of non-core assets totaled $44.6 million compared to $7.1 million in the first nine months period of 2004. Provident will continue to seek opportunities to dispose of its non-core properties given the competitive property market.

The 2005 COGP capital budget is $80.9 million.



Depletion, depreciation and accretion (DD&A)

Three months ended Nine months ended
COGP September 30, September 30,
---------------------------------------------------------------------
($000s, except % %
per boe data) 2005 2004 Change 2005 2004 Change
---------------------------------------------------------------------

DD&A $ 39,363 $ 46,327 (15) $122,120 $114,956 6
DD&A per boe $ 16.49 $ 15.52 6 $ 16.29 $ 15.12 8
---------------------------------------------------------------------
---------------------------------------------------------------------


The COGP DD&A of $16.49 per boe increased six percent for the third quarter of 2005 compared to $15.52 per boe for the third quarter of 2004. The increase is mainly due to the cost of acquiring proved reserves in the second quarter of 2004 in western Canada in an environment where reserve costs escalated with higher commodity prices. Acquiring proved reserves in 2004 at a higher cost than Provident's historical asset base, as well as higher drilling costs result in a higher per boe DD&A charge going forward.

In the third quarter 2005 accretion expense associated with asset retirement obligations of $0.8 million compared to $0.6 million in the comparable period of 2004. For the nine months ended September 30, 2005 the accretion expense was $2.5 million compared to $1.9 million in the comparable period of 2004. Provident expects a small decrease in accretion expense going forward as a result of the non-core property disposition.

USOGP segment review

The USOGP business unit incorporates activities from Provident's subsidiary, Breitburn Energy LP (Breitburn), an oil and gas exploitation and production business based in Los Angeles, California. Breitburn was purchased June 15, 2004. A comparative discussion and analysis for the nine months ended September 30, 2004 have not been disclosed separately as the USOGP operations were incorporated into Provident's results from June 15, 2004 and second quarter 2004 results were immaterial.

On March 2, 2005 Breitburn acquired Nautilus Resources, LLC, a U.S. private company with operations focused in the Big Horn and Wind River basins of Wyoming for cash consideration of $90.2 million.



USOGP pricing

The following prices are net of transportation expenses.

Three months ended Nine months ended
USOGP September 30, September 30,
---------------------------------------------------------------------
2005 2004 2005
---------------------------------------------------------------------
Realized pricing
before hedging
Light/medium oil and natural
gas liquids (Cdn$ per bbl) $ 64.62 $ 52.90 $ 57.63
Natural Gas (Cdn $ per mcf) $ 8.10 $ 7.67 $ 7.65
---------------------------------------------------------------------
---------------------------------------------------------------------


The majority of USOGP oil production is light, sweet crude that attracts smaller differentials to benchmark prices relative to heavier blends. However, the oil production from the recently acquired Nautilus properties is heavier and attracts slightly wider differentials. Production from the former Nautilus properties represents approximately 29 percent of third quarter production.



Production

Three months ended Nine months ended
USOGP September 30, September 30,
---------------------------------------------------------------------
2005 2004 2005
---------------------------------------------------------------------
Daily production
Crude oil - Light/Medium (bpd) 7,495 3,287 6,832
Natural gas liquids (bpd) 24 21 20
Natural gas (mcfd) 1,828 1,564 2,147
---------------------------------------------------------------------
Oil equivalent (boed) (1) 7,824 3,569 7,210
---------------------------------------------------------------------
---------------------------------------------------------------------


USOGP production increased 4,255 boed or 119 percent to 7,824 boed in the third quarter of 2005 when compared to the third quarter of 2004. The increase is primarily attributable to the production from the Nautilus properties acquired on March 2, 2005 as well as from Orcutt which was acquired on October 4, 2004. In total, the Nautilus properties added 2,400 boed and Orcutt added 1,500 boed, to production in the third quarter. Production from the original California properties saw an increase of over 450 boed in the third quarter of 2005 when compared to the third quarter of 2004.

USOGP expects production for the remainder of the year in the range of 7,500 to 7,800 boed, and for the full year of 2005 to be 7,200 to 7,400 boed. The production is down slightly from previous estimates, mainly due to the high rate of industry activity in the recent months impacting the availability of rigs and other oilfield services.

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 2005 and $0.7 million in the nine months ended September 30, 2005) on behalf of third parties.



Three months ended Nine months ended
USOGP September 30, September 30,
---------------------------------------------------------------------
($ 000s, except
per boe amounts) 2005 2004 2005
---------------------------------------------------------------------

Oil
Revenue $ 44,700 $ 16,007 $ 107,723
Realized loss on non-hedging
derivative instrument (5,780) (344) (11,448)
Royalties (4,350) (1,531) (10,318)
---------------------------------------------------------------------
Net revenue $ 34,570 $ 14,132 $ 85,957
---------------------------------------------------------------------
---------------------------------------------------------------------
Net revenue (per bbl) $ 50.13 $ 46.74 $ 46.09
Royalties as a percentage
of revenue 9.7% 9.6% 9.6%
---------------------------------------------------------------------

Natural gas
Revenue $ 1,363 $ 1,103 $ 4,481
Royalties (187) (140) (618)
---------------------------------------------------------------------
Net revenue $ 1,176 $ 963 $ 3,863
---------------------------------------------------------------------
---------------------------------------------------------------------
Net revenue (per mcf) $ 6.99 $ 6.69 $ 6.59
Royalties as a percentage
of revenue 13.7% 12.7% 13.8%
---------------------------------------------------------------------

Natural gas liquids
Revenue $ 102 $ 94 $ 260
Royalties (3) (5) (7)
---------------------------------------------------------------------
Net revenue $ 99 $ 89 $ 253
---------------------------------------------------------------------
---------------------------------------------------------------------
Net revenue (per bbl) $ 45.12 $ 45.04 $ 46.47
Royalties as a percentage
of revenue 2.5% 5.3% 2.5%
---------------------------------------------------------------------

Total
Revenue $ 46,165 $ 17,204 $ 112,464
Realized loss on non-hedging
derivative instrument (5,780) (344) (11,448)
Royalties (4,540) (1,676) (10,943)
---------------------------------------------------------------------
Net revenue $ 35,845 $ 15,184 $ 90,073
---------------------------------------------------------------------
---------------------------------------------------------------------
Net revenue (per boe) $ 49.80 $ 46.25 $ 45.76
Royalties as a percentage
of revenue 9.8% 9.7% 9.7%
---------------------------------------------------------------------
---------------------------------------------------------------------

Royalty rates in the U.S. are significantly lower than in Canada.


Production expenses

Three months ended Nine months ended
USOGP September 30, September 30,
---------------------------------------------------------------------
($ 000s, except per
boe amounts) 2005 2004 2005
---------------------------------------------------------------------
Production expenses $ 10,652 $ 5,167 $ 28,003
Production expenses (per boe) $ 14.80 $ 15.74 $ 14.23
---------------------------------------------------------------------
---------------------------------------------------------------------


Production expenses were $14.80 per boe in the third quarter of 2005 down $0.94 per boe or six percent from the third quarter of 2004. Continuing strong crude oil prices have resulted in USOGP field operations continuing to focus on a return to production or to maintain production on wells with higher operating costs. Year-to-date operating costs of $14.23 per boe are nine percent below the $15.62 per boe incurred in the period from June 15 to December 31, 2004. USOGP operating costs for the remainder of 2005 are expected to average between $14.75 and $15.25 per boe.

General and administrative

The following table does not incorporate the USOGP portion of non-cash general and administrative charges associated with the USOGP unit appreciation rights plan. Year-to-date non-cash expenses of $4.1 million have been recorded for the unit appreciation rights plan.



Three months ended Nine months ended
USOGP September 30, September 30,
---------------------------------------------------------------------
($ 000s, except per
boe amounts) 2005 2004 2005
---------------------------------------------------------------------
Cash general and
administrative $ 2,870 $ 1,461 $ 6,965
Cash general and
administrative per boe $ 3.99 $ 4.45 $ 3.54
---------------------------------------------------------------------
---------------------------------------------------------------------


Cash general and administrative expenses were $2.9 million or $3.99 per boe in the third quarter of 2005 compared to $1.5 million or $4.45 per boe in the third quarter of 2004. The addition of Nautilus on March 2, 2005 was absorbed without a significant increase in general and administrative expenses however costs associated with compliance (including costs associated with the implementation of procedures and documentation to be in compliance with the U. S. Sarbanes-Oxley Act) and a more competitive landscape impacting the cost of hiring and compensating employees continue to put upward pressure on general and administrative costs.

Year to date general and administrative expenses of $3.54 per boe were $1.31 per boe or 27 percent lower than the $4.85 per boe incurred in the period from June 15 to December 31, 2004. This is primarily due to the addition of Orcutt on October 4, 2004 and the addition of Nautilus on March 2, 2005. The acquisitions added in excess of 3,700 boed of production without a significant increase in general and administrative expenses.



Operating netback

Three months ended Nine months ended
USOGP September 30, September 30,
---------------------------------------------------------------------
($ per boe) 2005 2004 2005
---------------------------------------------------------------------

USOGP oil equivalent netback per boe

Gross production revenue $ 64.14 $ 52.40 $ 57.14
Royalties (6.31) (5.10) (5.56)
Operating costs (14.80) (15.74) (14.23)
---------------------------------------------------------------------
Field Operating Netback $ 43.03 $ 31.56 $ 37.35
---------------------------------------------------------------------
---------------------------------------------------------------------
Cash hedging (8.03) (1.05) (5.82)
---------------------------------------------------------------------
Operating netback
after hedging $ 35.00 $ 30.51 $ 31.53
---------------------------------------------------------------------
---------------------------------------------------------------------


Three months ended Nine months ended
USOGP September 30, September 30,
---------------------------------------------------------------------
($ per bbl) 2005 2004 2005
---------------------------------------------------------------------
USOGP crude oil and NGL's netback per bbl

Gross production revenue $ 64.77 $ 52.90 $ 57.73
Royalties (6.29) (5.05) (5.52)
Operating costs (14.80) (15.74) (14.23)
---------------------------------------------------------------------
Field Operating Netback $ 43.68 $ 32.11 $ 37.98
---------------------------------------------------------------------
Cash hedging (8.36) (1.13) (6.12)
---------------------------------------------------------------------
Operating netback
after hedging $ 35.32 $ 30.98 $ 31.86
---------------------------------------------------------------------
---------------------------------------------------------------------


Three months ended Nine months ended
USOGP September 30, September 30,

---------------------------------------------------------------------
($ per mcf) 2005 2004 2005
---------------------------------------------------------------------
USOGP natural gas
netback per mcf
Gross production revenue $ 8.10 $ 7.67 $ 7.65
Royalties (1.11) (0.97) (1.05)
Operating costs (2.47) (2.62) (2.37)
---------------------------------------------------------------------
Field and Operating Netback $ 4.52 $ 4.08 $ 4.23
---------------------------------------------------------------------
---------------------------------------------------------------------

Operating netbacks in the third quarter of 2005 remain strong driven
by high commodity prices partially offset by increased production
costs and opportunity costs associated with hedge activities.


Capital expenditures

USOGP capital expenditures, excluding corporate acquisitions, for the third quarter of 2005 totaled $11.2 million. $8.1 million of the capital expenditures were directed at drilling, optimization and facility upgrades at West Pico, Santa Fe Springs and Orcutt. At the newly acquired Nautilus fields in Wyoming $1.4 million was directed at optimization projects with a further $1.7 million 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. In addition, optimization capital continues to incorporate returning previously uneconomic wells to production to take advantage of high oil prices.

For the nine months ended September 30, 2005 capital expenditures, excluding corporate acquisitions, totaled $41.4 million. Of this, $31.7 million was directed at drilling, optimization and facility upgrades at West Pico, Santa Fe Springs and Orcutt, $3.7 million was directed to the purchase of real estate adjacent to the West Pico site, $2.5 million was directed at optimization projects at the newly acquired Nautilus fields and $3.5 million was directed at optimization projects at smaller fields and office equipment.

The March 2, 2005 corporate acquisitions of Nautilus added $99.9 million to property, plant and equipment for the nine months ended September 30, 2005.



Depletion, depreciation and accretion (DD&A)

Three months ended Nine months ended
USOGP September 30, September 30,
---------------------------------------------------------------------
($ 000s, except per
boe amounts) 2005 2004 2005
---------------------------------------------------------------------

DD&A $ 7,147 $ 2,314 $ 18,931
DD&A per boe $ 9.93 $ 7.05 $ 9.62
---------------------------------------------------------------------
---------------------------------------------------------------------

The USOGP's DD&A rate is low due to the long-lived nature of the
assets.


Midstream services and marketing business segment review

Midstream processes natural gas liquids (NGL) at the Redwater fractionation, storage and transportation facility located in Edmonton, Alberta.

Operations - managed volumes

Provident managed 61,760 bpd over the third quarter. Product managed in the third quarter of 2004 was 58,400 bpd which was marginally impacted by an outage on the Liquids Gathering System (LGS). Year-to-date managed volumes averaged 59,870 bpd compared to 59,250 bpd for the first nine months of 2004.

Revenues

For the third quarter of 2005, product sales and services revenues were $181.0 million and year-to-date revenues were $612.5 million. Revenue figures are after elimination of intersegment transactions and include product sales related to transportation and fractionation (T&F) processing and marketing, revenues generated through storage and distribution services and oil sales generated through oil marketing activities. Comparable figures for 2004 are $217.0 million and $588.2 million, respectively. The majority of NGL revenues are earned pursuant to long-term contracts and annual evergreen purchase and sales commitments.

Cost of goods sold

The cost of goods sold was $157.7 million for the third quarter of 2005 and $541.5 million year-to-date. These figures are after elimination of intersegment transactions and relate to NGL product sales revenue included in the product sales and services revenue, where Provident has purchased natural gas liquids and to oil purchased pursuant to oil marketing activities. The NGL costs would be applicable to the T&F and marketing contracts and a small percentage of volume delivered from the Younger facility on which Provident retains fractionation risk. The majority of the natural gas liquids are purchased pursuant to long-term contracts and annual evergreen purchase commitments.

Other expenses

The plant has modern technology and low cost operations. Third quarter 2005
operating costs of $8.6 million and nine months ended September 30, 2005 of $24.7 million (quarter and nine months ended September 30, 2004 - $8.0 million and $27.9 million respectively) represent normal operations. General and administrative expenses were $1.7 for the third quarter 2005 (2004 - $1.7 million), and $5.8 million for the nine months ended September 30, 2005 (2004 - $4.1 million). Interest for the third quarter was $1.0 million for 2005 (2004 - $1.7 million), and $3.8 million for the nine months ended September 30, 2005 (2004 - $6.3 million). Depreciation expense was $2.5 million for the three months ended September 30, 2005 (2004 - $2.3 million), and $7.5 million for the nine months ended September 30, 2005 (2004 - $6.8 million).

Earnings before interest, taxes, depletion, depreciation, accretion, and non-cash revenue (EBITDA) and cash flow from operations

The third quarter of 2005 results for the Midstream services and marketing business unit reflected in EBITDA, cash flow and net income benefited from continuing efficient operations, marketing opportunities and increased revenues associated with storage and distribution services. Third quarter 2005 EBITDA of $13.0 million increased $2.0 million or 18 percent from $11.0 million in the third quarter of 2004. For the nine months ended September 30, 2005 EBITDA increased $9.0 million or 28 percent to $41.1 million from $32.1 million in the comparable 2004 period. Cash flow for the third quarter of 2005 was $12.2 million, an increase of $2.9 million or 32 percent above the $9.3 million for the third quarter 2004. For the nine months ended September 30, 2005 cash flow was $37.9 million, an increase of $11.8 million or 46 percent above the $26.1 million for the comparable period of 2004. Third quarter net income at $7.7 million was 41 percent below the $13.1 million of net income recorded in the third quarter of 2004.

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

Gain on sale of marketing contracts

On May 1, 2005 the Trust disposed of certain marketing contracts for net proceeds of $5.5 million and recorded a gain of $5.2 million net of disposal costs. The sale of these contracts will not materially impact cash flows and has been recognized through the Midstream services and marketing segment. During 2004 the marketing business generated $203.0 million in revenues. For the four months period ended April 30, 2005 the marketing business generated $105.7 million in revenues. The sale of these contracts is not expected to have a material impact on the cash flow or net income of the Midstream and marketing segment.

Capital expenditures

Midstream capital expenditures, excluding corporate acquisitions, for the third quarter of 2005 totaled $1.1 million. $1.0 million of the capital was spent on the new condensate offloading and terminalling facilities recently announced.

For the nine months ended September 30, 2005 capital expenditures, excluding corporate acquisitions, totaled $1.7 million, this amount was directed at the condensate and multi-product loading and unloading facilities.



Distributions

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

---------------------------------------------------------------------
Distribution Amount
Record Date Payment Date (Cdn$) (US$)(1)
---------------------------------------------------------------------
2005
January 20, 2005 February 15, 2005 $ 0.12 0.10
February 18, 2005 March 15, 2005 0.12 0.10
March 21, 2005 April 15, 2005 0.12 0.10
April 20, 2005 May 13, 2005 0.12 0.10
May 19, 2005 June 15, 2005 0.12 0.10
June 20, 2005 July 15, 2005 0.12 0.10
July 20, 2005 August 15, 2005 0.12 0.10
August 19, 2005 September 15, 2005 0.12 0.10
September 20, 2005 October 14, 2005 0.12 0.10
---------------------------------------------------------------------
2005 Cash Distributions paid as declared $ 1.08 0.90
---------------------------------------------------------------------
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, 2005
- Distributions paid as declared $ 9.15 6.40
---------------------------------------------------------------------
---------------------------------------------------------------------
(1) exchange rate based on the Bank of Canada noon rate on the
payment date.


For Canadian tax purposes, 2004 distributions were determined to be 71 percent taxable and 29 percent a tax deferred return of capital in the hands of Canadian unitholders. Distributions received by U.S. resident unitholders in 2004 were classified as 83 percent qualified dividend and 17 percent tax deferred return of capital. In both Canada and the U.S., the tax-deferred portion would usually be treated as an adjustment to the cost base of the units. Unitholders or potential unitholders should consult their own legal or tax advisors as to their particular income tax consequences of holding Provident units.

Foreign ownership

As at September 2005, based on information received from the transfer agent and financial intermediaries, an estimated 85 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. Since January 2002, Provident has seen increased trading volumes and levels of ownership by non-residents of Canada.

In March of 2004, the Canadian government announced that it would change current legislation to ensure that all mutual fund trusts, including resources trusts, would be subject to a minimum 50 percent Canadian ownership standard and that there would be withholding taxes on all distributions to non-residents of Canada. The specific legislation providing the details of the changes was tabled in mid-September. These changes would have required that Provident have not more than 50 percent foreign ownership by January 1, 2007.

In December of 2004, Canada's Minister of Finance tabled a Notice of Ways and Means Motion to Implement Budget 2004 Measures (the Notice). The Notice does not include restrictions upon foreign ownership of mutual fund trusts as was previously proposed in draft legislation on September 16, 2004. Under the terms of the Notice, non-resident taxable and non-resident tax-exempt accounts will have tax withheld by the Canadian government on the entire distribution, including the return of capital and return on capital portions. The Notice is effective January 1, 2005.

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.

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. 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.

Federal Tax Consultation Process

On September 8, 2005 the Government of Canada issued a consultation paper entitled "Tax and Other Issues Related to Publicly Listed Flow-Through Entities," regarding the tax treatment of income trusts. Provident recognizes the government's responsibility to ensure appropriate tax policy, and appreciates the opportunity to participate in the consultation. The government's consultation paper discusses two potential issues around flow-through entities such as income trusts: tax revenue implications and economic efficiency concerns.

Provident believes that the rapid growth in the trust sector and the strong returns that the sector has provided to investors demonstrate the effectiveness of this uniquely Canadian legal structure. Provident's recent acquisition of a major continental NGL business is an excellent example of how the trust structure works to promote Canadian ownership and disciplined management of assets in mature industries.

Business prospects

Provident intends to execute a balanced portfolio strategy. In the COGP business internal development projects with a board approved capital budget of $80.9 million are planned. Acquisitions of interest in properties close to properties already owned or partially owned by Provident will be pursued. In the USOGP business internal development projects are planned with a board approved capital budget of $46.0 million. Major corporate or property acquisitions are being evaluated. In the Midstream Services business Provident will expand and build upon the Redwater business and evaluate additional infrastructure assets with a goal of adding quality assets at reasonable prices. The goal of these strategies is to maintain and increase per unit distributable cash flow and net asset value.

Changes in accounting policies

Exchangeable securities - non-controlling interest

The Canadian Institute of Chartered Accountants issued an amendment to standard EIC-151 "Exchangeable Securities Issued by Subsidiaries of Income Trusts" that states that exchangeable securities issued by a subsidiary of an income trust should be reflected as either non-controlling interest or debt on the consolidated balance sheet unless they meet certain criteria. The exchangeable shares issued by Provident Acquisitions Inc. and Provident Energy Ltd. corporate subsidiaries of the Trust, are considered under this standard to be transferable to third parties. EIC-151 states that if the exchangeable shares are transferable to a third party, they should be reflected as non-controlling interest. Previously, the exchangeable shares were reflected as a component of unitholders' equity.

As a result of this change in accounting policy, the Trust has reflected non-controlling interest of $9.8 million and $35.9 million, respectively, on the Trust's consolidated balance sheet as at September 30, 2005 and December 31, 2004. Consolidated net income or loss has been adjusted for the earnings attributable to the non-controlling interest of $0.4 million in the nine months ended September 30, 2005 and the loss of $0.4 million in the nine month period ended September 30, 2004. As at September 30, 2005 unitholders' equity was reduced by $7.8 million and non-controlling interest on the consolidated balance sheet increased by $ 9.8 million. In accordance with the transitional provisions of EIC-151, retroactive application has been applied with restatement of prior periods. The retroactive application of this abstract as at March 31, 2005 and December 31, 2004 was an accumulated loss of $1.4 and $1.5 million respectively. Cash flow was not affected by this change.

Business risks

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

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

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

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

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

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

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

- income tax legislation relating to income trusts.

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

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

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

Provident strives to minimize these business risks by:

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

- 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 cash flow available for distribution;

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

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

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

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

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

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



Unit trading activity

The following table summarizes the unit trading activity of the
Provident units for the nine months ended September 30, 2005 on both
the Toronto Stock Exchange and the American Stock Exchange:

Nine
($ 000s, except per months ended
boe amounts) Q1 Q2 Q3 September 30
---------------------------------------------------------------------
TSE - PVE.UN (Cdn$)
High $ 12.60 $ 13.05 $ 14.29 $ 14.29
Low $ 11.17 $ 11.82 $ 12.91 $ 11.17
Close $ 11.98 $ 12.82 $ 14.14 $ 14.14
Volume (000s) 26,122 15,951 22,375 64,448
---------------------------------------------------------------------
---------------------------------------------------------------------
AMEX - PVX (US$)
High $ 10.40 $ 10.55 $ 12.42 $ 12.42
Low $ 9.15 $ 9.48 $ 10.65 $ 9.15
Close $ 9.89 $ 10.49 $ 12.19 $ 12.19
Volume (000s) 64,223 46,548 55,372 166,143
---------------------------------------------------------------------
---------------------------------------------------------------------


Segmented information by quarter
---------------------------------------------------------------------
($000s except for per
unit amounts) 2005
---------------------------------------------------------------------
First Second Third Year-to-
Quarter (1) Quarter Quarter Date
---------------------------------------------------------------------
Financial - consolidated
Revenue $ 322,023 $ 300,504 $ 295,060 $ 917,587
Cash flow $ 64,137 $ 64,435 $ 86,318 $ 214,890
Net income $ (2,783) $ 26,822 $ 18,386 $ 42,425
Unitholder
distributions $ 51,734 $ 57,001 $ 59,333 $ 168,068
Distributions
per unit $ 0.36 $ 0.36 $ 0.36 $ 1.08
--------------------------------------------- ----------------------

Oil and gas production
Cash revenue $ 100,447 $ 104,478 $ 124,073 $ 328,998
Earnings before
interest, DD&A, taxes
and other non-cash
items $ 59,262 $ 63,584 $ 81,670 $ 204,516
Cash flow $ 48,937 $ 53,868 $ 72,193 $ 174,998
Net income (loss) $ (15,046) $ 14,681 $ 10,702 $ 10,337
--------------------------------------------- ----------------------
--------------------------------------------- ----------------------

Midstream services and marketing
Cash revenue $ 245,338 $ 186,635 $ 180,875 $ 612,848
Earnings before
interest, DD&A
and taxes $ 16,380 $ 11,765 $ 12,978 $ 41,123

Cash flow $ 15,200 $ 10,567 $ 14,125 $ 39,892
Net income $ 12,263 $ 12,141 $ 7,684 $ 32,088
---------------------------------------------------------------------

Operating
Oil and gas production
Light/medium oil (bpd) 14,388 15,891 15,583 15,288
Heavy oil (bpd) 5,547 4,644 4,075 4,750
Natural gas
liquids (bpd) 1,756 1,454 1,523 1,577
Natural gas (mcfd) 80,466 79,126 75,523 78,353
Oil equivalent (boed) 35,102 35,177 33,768 34,674
---------------------------------------------------------------------

(Cdn $)
Average selling price net of
transportation expense
Light/medium oil
per bbl $ 49.32 $ 51.20 $ 62.95 $ 54.51
(before hedges)
Light/medium oil
per bbl $ 40.93 $ 42.18 $ 49.82 $ 44.34
(including hedges)
Heavy oil per bbl $ 25.85 $ 26.03 $ 46.74 $ 31.95
(before hedges)
Heavy oil per bbl $ 25.78 $ 26.03 $ 46.74 $ 31.92
(including hedges)
Natural gas liquids
per barrel $ 45.30 $ 47.75 $ 54.27 $ 48.96
Natural gas per mcf $ 6.76 $ 7.29 $ 8.43 $ 7.48
(before hedges)
Natural gas per mcf $ 6.74 $ 7.13 $ 8.03 $ 7.29
(including hedges)
---------------------------------------------------------------------

Midstream services and marketing
Redwater managed
volumes (bpd) 61,590 58,200 61,760 59,870
---------------------------------------------------------------------
---------------------------------------------------------------------
(1) Restated - note 2


Segmented information by quarter

($000s except per
unit amounts) 2004(1)
---------------------------------------------------------------------
First Second Third Fourth YTD
Quarter Quarter Quarter Quarter Total
--------- --------- --------- --------- -----------
Financial - consolidated
Revenue $ 234,947 $ 218,304 $ 287,171 $ 369,435 $ 1,109,857
Cash flow $ 36,269 $ 36,530 $ 54,076 $ 58,371 $ 185,246
Net income $ (5,995)$ (6,873)$ (4,221)$ 38,314 $ 21,225
Unitholder
distributions $ 31,036 $ 35,039 $ 46,489 $ 52,064 $ 164,628
Distributions
per unit $ 0.36 $ 0.36 $ 0.36 $ 0.36 $ 1.44

Oil and gas production
Cash revenue $ 54,865 $ 59,316 $ 89,129 $ 91,569 $ 294,879
Earnings before
interest, DD&A,
taxes and other
non-cash items $ 30,741 $ 34,974 $ 51,767 $ 50,498 $ 167,980
Cash flow $ 26,386 $ 29,593 $ 44,825 $ 41,798 $ 142,602
Net income
(loss) $ (9,761)$ (10,950)$ (17,356)$ 27,490 $ (10,577)
---------------------------------------------------------------------

Midstream services and marketing
Cash revenue $ 233,031 $ 218,388 $ 287,679 $ 288,768 $ 1,027,866
Earnings before
interest, DD&A
and taxes $ 12,197 $ 8,945 $ 10,986 $ 17,957 $ 50,085

Cash flow $ 9,883 $ 6,937 $ 9,251 $ 16,573 $ 42,644
Net income $ 3,766 $ 4,077 $ 13,135 $ 10,824 $ 31,802
---------------------------------------------------------------------
---------------------------------------------------------------------

Operating
Oil and gas
production
Light/medium
oil (bpd) 5,965 7,861 12,674 14,012 10,146
Heavy oil (bpd) 6,588 6,537 6,770 6,536 6,608
Natural gas
liquids (bpd) 1,130 1,267 1,803 1,770 1,494
Natural gas
(mcfd) 63,859 68,007 88,642 87,339 77,022
Oil equivalent
(boed) 24,326 27,000 36,021 36,874 31,085
---------------------------------------------------------------------

(Cdn $)
Average selling price net of
transportation expense
Light/medium oil
per bbl
(before hedges) $ 39.00 $ 42.28 $ 48.59 $ 45.83 $ 45.01
Light/medium oil
per bbl
(including
hedges) $ 26.15 $ 29.97 $ 38.00 $ 33.88 $ 33.29
Heavy oil per
bbl (before
hedges) $ 26.84 $ 28.26 $ 34.23 $ 25.33 $ 28.72
Heavy oil per
bbl (including
hedges) $ 22.80 $ 23.26 $ 25.72 $ 22.17 $ 23.51
Natural gas
liquids per
barrel $ 37.03 $ 40.55 $ 40.88 $ 42.80 $ 40.68
Natural gas per
mcf (before
hedges) $ 6.40 $ 7.01 $ 6.47 $ 6.56 $ 6.60
Natural gas
per mcf
(including
hedges) $ 6.31 $ 6.26 $ 6.05 $ 6.31 $ 6.23
---------------------------------------------------------------------

Midstream services and marketing
Redwater managed
volumes (bpd) 67,279 51,393 58,400 58,436 57,485
---------------------------------------------------------------------
---------------------------------------------------------------------
(1) Restated - note 2.


Segmented information by quarter
---------------------------------------------------------------------
($000s except per unit amounts) 2003(1)
---------------------------------------------------------------------
First Second Third Fourth YTD
Quarter Quarter Quarter Quarter Total
--------- --------- --------- --------- -----------
Financial - consolidated
Revenue $ 66,710 $ 57,520 $ 67,622 $214,477 $406,329
Cash flow $ 40,372 $ 30,106 $ 27,544 $ 30,343 $128,365
Net income $ (9,853) $ 19,828 $ (4,088) $ 16,610 $ 22,497
Unitholder
distributions $ 33,091 $ 35,528 $ 28,969 $ 32,024 $129,612
Distributions
per unit $ 0.60 $ 0.60 $ 0.47 $ 0.39 $ 2.06
---------------------------------------------------------------------
---------------------------------------------------------------------

Oil and gas production
Cash revenue $ 66,710 $ 57,520 $ 55,260 $ 54,648 $234,138
Earnings before
interest, DD&A
and taxes $ 26,845 $ 33,989 $ 31,517 $ 25,660 $118,011
Cash flow $ 40,372 $ 30,106 $ 27,463 $ 21,620 $119,561
Net income $(11,811) $ 19,828 $ (4,567) $ 10,268 $ 16,278
---------------------------------------------------------------------

Midstream services and marketing
Cash revenue $ - $ - $ 23,713 $173,435 $197,148
Earnings before
interest, DD&A
and taxes $ - $ - $ - $ 10,242 $ 10,242
Cash flow $ - $ - $ 81 $ 8,723 $ 8,804
Net income $ - $ - $ 85 $ 8,018 $ 8,103
---------------------------------------------------------------------

Operating
Oil and gas
production
Light/medium
oil (bpd) 7,285 6,770 6,748 6,454 6,812
Heavy oil (bpd) 6,245 6,700 7,495 7,151 6,902
Natural gas
liquids (bpd) 1,085 1,162 1,276 1,145 1,167
Natural gas
(mcfd) 83,924 72,898 73,090 68,657 74,596
Oil equivalent
(boed) 28,602 26,781 27,701 26,193 27,314
---------------------------------------------------------------------

(Cdn $ per boe)
Average selling price net of
transportation expense
Light/medium
oil per bbl
(before hedges) $ 43.64 $ 33.57 $ 33.49 $ 32.79 $ 36.02
Light/medium
oil per bbl
(including
hedges) $ 32.04 $ 29.18 $ 28.24 $ 26.61 $ 29.09
Heavy oil per bbl
(before hedges) $ 31.63 $ 23.47 $ 24.17 $ 20.61 $ 24.74
Heavy oil per bbl
(including
hedges) $ 24.63 $ 21.92 $ 22.16 $ 20.25 $ 22.09
Natural gas
liquids per
barrel $ 45.13 $ 37.16 $ 28.26 $ 34.48 $ 35.87
Natural gas
per mcf
(before hedges) $ 7.94 $ 6.87 $ 5.88 $ 5.62 $ 6.63
Natural gas
per mcf
(including
hedges) $ 6.49 $ 5.64 $ 5.14 $ 5.48 $ 5.71
---------------------------------------------------------------------

Midstream services and marketing
Redwater managed
volumes (bpd) - - - 66,356 n/a
---------------------------------------------------------------------
---------------------------------------------------------------------
(1) Restated - note 2.


PROVIDENT ENERGY TRUST
CONSOLIDATED BALANCE SHEETS
Canadian dollars (000s)
(unaudited) As at As at
September 30, December 31,
2005 2004
------------------------------
(restated note 2)

Assets
Current assets
Cash $ 66 $ 244
Accounts receivable 176,058 143,142
Petroleum product inventory 35,115 17,151
Deferred derivative loss 589 2,144
Prepaid expenses 11,711 10,265
---------------------------------------------------------------------
223,539 172,946

Cash reserve for future site
reclamation 2,009 1,454
Investments 3,600 3,000
Deferred financing charges 6,236 5,584
Property, plant and equipment 1,286,993 1,299,654
Goodwill 330,944 330,944
---------------------------------------------------------------------
$ 1,853,321 $ 1,813,582
---------------------------------------------------------------------
---------------------------------------------------------------------
Liabilities
Current liabilities
Accounts payable and accrued
liabilities $ 191,710 $ 171,412
Cash distributions payable 18,459 15,416
Distribution payable to
non-controlling interests 506 271
Financial derivative instruments 42,324 24,524
---------------------------------------------------------------------
252,999 211,623

Long-term debt - revolving term
credit facility (note 5) 182,171 262,750
Long-term debt - convertible
debentures (note 5) 159,079 169,456
Asset retirement obligation
(note 6) 30,467 40,506
Long-term financial derivative
instruments 4,273 -
Future income taxes 65,095 70,629

Non-controlling interests
USOGP operations 12,878 13,649
Exchangeable shares (note 7) 9,838 35,921

Unitholders' equity
Unitholders' contributions
(note 8) 1,703,371 1,438,393
Convertible debentures equity
component (note 2) 11,413 9,785
Contributed surplus (note 10) 1,399 2,002
Cumulative translation adjustment
(note 2) (41,735) (28,848)
Accumulated income 42,787 362
Accumulated cash distributions
(note 11) (580,714) (412,646)
---------------------------------------------------------------------
1,136,521 1,009,048
---------------------------------------------------------------------
$ 1,853,321 $ 1,813,582
---------------------------------------------------------------------
---------------------------------------------------------------------
Subsequent event (note 12)


PROVIDENT ENERGY TRUST
CONSOLIDATED STATEMENT OF OPERATIONS AND ACCUMULATED INCOME (LOSS)
Canadian dollars (000s except per unit amounts)
(unaudited)
Three months ended Nine months ended
September 30, September 30,
------------------------------------------
2005 2004 2005 2004
------------------------------------------
(restated (restated
note 2) note 2)


Revenue (note 9)
Revenue $ 326,711 $ 327,160 $ 988,060 $ 838,231
Realized loss on
financial
derivative
instruments (21,763) (24,184) (46,214) (50,673)
Unrealized loss
on financial
derivative
instruments (9,888) (15,805) (24,259) (47,136)
---------------------------------------------------------------------
295,060 287,171 917,587 740,422

Expenses
Cost of goods sold 157,749 192,742 541,548 519,995
Production, operating
and maintenance 43,215 40,187 124,510 97,972
Transportation 1,390 1,436 4,418 3,364
Depletion, depreciation
and accretion 49,021 50,905 148,571 124,377
General and
administrative 9,919 7,450 27,556 18,457
Non cash general and
administrative
(note 10) 2,431 1,860 4,853 1,165
Interest on bank debt 1,535 3,378 6,775 8,451
Interest and accretion
on convertible
debentures
(notes 2 and 5) 4,651 4,708 16,744 12,357
Amortization of
deferred financing
charges (note 2) 345 359 903 1,077
Foreign exchange gain
and other (1,880) (640) (1,988) (3,407)
Loss on redemption of
convertible debentures
(note 5) - - 49 -
Gain on sale of
marketing contracts
(note 4) - - (5,188) -
---------------------------------------------------------------------
268,376 302,385 868,751 783,808
---------------------------------------------------------------------
---------------------------------------------------------------------

Income (loss) before
taxes and
non-controlling
interests 26,684 (15,214) 48,836 (43,386)
---------------------------------------------------------------------

Capital taxes 767 1,202 3,677 3,374
Current and
withholding taxes 2,553 326 6,924 618
Future income tax
expense (recovery) 4,298 (12,991) (5,534) (30,577)
---------------------------------------------------------------------
7,618 (11,463) 5,067 (26,585)
Net income (loss)
before non-controlling
interests 19,066 (3,751) 43,769 (16,801)
---------------------------------------------------------------------
Non-controlling
interests income
(loss)
USOGP operations 527 566 926 696
Exchangeable shares
(note 7) 153 (96) 418 (408)
---------------------------------------------------------------------
Net income (loss) 18,386 (4,221) 42,425 (17,089)
---------------------------------------------------------------------
---------------------------------------------------------------------

Accumulated income
(loss), beginning
of period $ 24,401 $ (23,775)$ 1,844 $ (4,029)
Retroactive
application of
changes in
accounting policies
(note 2) - - (1,482) (6,878)
---------------------------------------------------------------------
Accumulated income
(loss), beginning
of period, restated 24,401 (23,775) 362 (10,907)
---------------------------------------------------------------------
---------------------------------------------------------------------
Accumulated income
(loss), end of
period $ 42,787 $ (27,996)$ 42,787 $ (27,996)
---------------------------------------------------------------------
Net income (loss)
per unit - basic $ 0.11 $ (0.03)$ 0.27 $ (0.16)
---------------------------------------------------------------------
---------------------------------------------------------------------
Net income (loss)
per unit - diluted $ 0.11 $ (0.03)$ 0.27 $ (0.16)
---------------------------------------------------------------------
---------------------------------------------------------------------


PROVIDENT ENERGY TRUST
CONSOLIDATED STATEMENT OF CASH FLOWS
Canadian Dollars (000s)
(unaudited)
Three months ended Nine months ended
September 30, September 30,
------------------------------------------
2005 2004 2005 2004
------------------------------------------
(restated (restated
note 2) note 2)
Cash provided by
operating activities
Net income (loss) for
the period $ 18,386 $ (4,221)$ 42,425 $ (17,089)
Add (deduct) non-cash
items:
Depletion,
depreciation and
accretion 49,021 50,905 148,571 124,377
Debenture accretion
and amortization of
deferred charges
(note 2) 1,558 1,105 4,330 2,951
Non-cash general and
administrative
(note 10) 2,431 1,860 4,853 1,165
Unrealized loss on
financial derivative
instruments (note 9) 9,888 15,805 24,259 47,136
Unrealized foreign
exchange loss (gain) 86 1,143 (129) (1,376)
Future income tax
expense (recovery) 4,298 (12,991) (5,534) (30,577)
Equity in earnings
of investee (30) - (90) -
Net income attributable
to non-controlling
interests 680 470 1,344 288
Loss on redemption of
convertible debentures
(note 5) - - 49 -
Gain on sale of
marketing contracts
(note 4) - - (5,188) -
---------------------------------------------------------------------
Cash flow from
operations before
changes in working
capital and site
restoration
expenditures 86,318 54,076 214,890 126,875
---------------------------------------------------------------------
Site restoration
expenditures (700) (1,096) (1,695) (2,083)
Change in non-cash
operating working
capital (3,653) (8,911) (27,322) (4,780)
---------------------------------------------------------------------
81,965 44,069 185,873 120,012
---------------------------------------------------------------------

Cash used for
financing activities
Increase (decrease)
of long-term debt (26,475) 10,818 (78,732) (16,225)
Proceeds of bridge
financing - - - 158,184
Repayment of bridge
financing - (158,184) - (158,184)
Declared distributions
to unitholders
(note 11) (59,333) (46,489) (168,068) (112,564)
Declared distributions
to non-controlling
interest (719) - (1,698) -
Issue of trust units,
net of issue costs 6,499 136,142 131,811 195,112
Issue of debentures,
net of costs (note 5) - 48,000 95,759 48,000
Redemption of
debentures, net of
costs (note 5) - - (2,997) -
Change in non-cash
financing working
capital (7,099) 10,625 (2,872) 7,230
---------------------------------------------------------------------
(87,127) 912 (26,797) 121,553
---------------------------------------------------------------------


Cash used for
investing activities
Net capital
expenditures and
OGP acquisitions (40,082) (30,715) (106,168) (58,559)
Acquisition of
Nautilus (note 3) - - (91,420) -
Acquisition of
Breitburn Energy
(note 3) - - - (165,649)
Acquisition of
Olympia Energy Inc.
(note 3) - - - (4,715)
Acquisition of
Viracocha Energy Inc.
(note 3) - - - (1,993)
Acquisition of Redwater - (1,300) - (1,300)
Acquisition of
investment - - (510) -
Proceeds from property
dispositions 44,639 - 44,639 7,114
Proceeds on sale of
marketing contracts
net of disposal costs
(note 4) - - 5,546 -
Reclamation fund
contributions (716) 1,254 (2,250) 87
Reclamation fund
withdrawals 700 - 1,695 -
Payment of financial
derivative instruments
(note 3) - - (8,137) (23,302)
Change in non-cash
investing working
capital 223 (14,098) (2,649) 6,896
---------------------------------------------------------------------
4,764 (44,859) (159,254) (241,421)
---------------------------------------------------------------------

Increase (decrease)
in cash (398) 121 (178) 143
Cash beginning of
period 464 67 244 45
---------------------------------------------------------------------
Cash end of period $ 66 $ 188 $ 66 $ 188
---------------------------------------------------------------------
Supplemental
disclosure of cash
flow information
Cash interest paid
including debenture
interest $ 6,893 $ 2,550 $ 22,012 $ 13,381
---------------------------------------------------------------------
---------------------------------------------------------------------


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


September 30, 2005

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, 2004, which are disclosed in the annual report filed by the Trust.

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, 2004 and are consistent with policies adopted in the third quarter of 2004 except as described in note 2.

2. Changes in accounting policies and practices

(i) Convertible debentures

Effective December 31, 2004, the Trust retroactively adopted the revised CICA Handbook Section 3860 ("HB 3860"), "Financial Instruments - Presentation and Disclosure" for financial instruments that may be settled at the issuer's option in cash or its own equity. The revised standard requires the Trust to classify proceeds from convertible debentures issued in 2002, 2003 and 2004 as either debt or equity based on fair value measurement and the substance of the contractual arrangement. The Trust previously presented the convertible debenture proceeds (net of financing costs) and related interest obligations as equity on the consolidated balance sheet on the basis that the Trust could settle its obligations in exchange for trust units. Issue costs on convertible debentures are recorded as deferred financing charges and are amortized over the life of the debenture.

The Trust's obligation to make scheduled payments of principal and interest constitutes a financial liability under the revised standard and exists until the instrument is either converted or redeemed. The holders' option to convert the financial liability into trust units is an embedded conversion option. The effect of the adoption of this standard is presented in note 5 to the financial statements.

(ii) Foreign currency translation

In the fourth quarter of 2004, the Trust reviewed its practices for U.S. operations and determined that such operations are self-sustaining as a result of the development of the Trust's management practices for U.S. operations. The accounts of self-sustaining foreign operations are translated using the current rate method, whereby assets and liabilities are translated at period-end exchange rates, while revenues and expenses are translated using rates for the period. Translation gains and losses related to the operations are deferred and included as a separate component of unitholders' equity. Previously, operations outside of Canada were considered to be integrated and translated using the temporal method. Under the temporal method, monetary assets and liabilities were translated at the period end exchange rates, other assets and liabilities at the historical rates and revenues and expenses at the rates for the period except depreciation, depletion and accretion, which were translated on the same basis as the related assets. This change in practice was adopted prospectively beginning October 1, 2004.

(iii) Exchangeable securities - non-controlling interest

The Canadian Institute of Chartered Accountants issued an amendment to EIC abstract 151 "Exchangeable Securities Issued by Subsidiaries of Income Trusts" that states that exchangeable securities issued by a subsidiary of an income trust should be reflected as either non-controlling interest or debt on the consolidated balance sheet unless they meet certain criteria. The exchangeable shares issued by Provident Acquisitions Inc. and Provident Energy Ltd. corporate subsidiaries of the Trust are considered under this standard to be transferable to third parties. EIC-151 states that if the exchangeable shares are transferable to a third party, they should be reflected as non-controlling interest. Previously, the exchangeable shares were reflected as a component of unitholders' equity.

As a result of this change in accounting policy, the Trust has reflected non-controlling interest of $9.8 million and $35.9 million, respectively, on the Trust's consolidated balance sheet as at September 30, 2005 and December 31, 2004. Consolidated net income or loss has been adjusted for the earnings attributable to the non-controlling interest of $0.4 million for the nine months ended September 30, 2005 and the loss of $0.4 million for the nine months ended September, 2004. As at September 30, 2005 unitholders' equity was reduced by $7.8 million and non-controlling interest on the consolidated balance sheet increased by $9.8 million. In accordance with the transitional provisions of EIC-151, retroactive application has been applied with restatement of prior periods. The retroactive application of this abstract as at March 31, 2005 and December 31, 2004 was an accumulated loss of $1.4 million and $1.5 million respectively. For the comparative periods ended March 31, 2004 and December 31, 2003 there were retroactive accumulated loss adjustments of $0.9 and $1.0 million respectively. The retroactive accumulated loss adjustments represent the cumulative net income attributable to the non controlling interest for prior periods. Cash flow was not affected by this change.

3. Acquisitions

(i) Acquisition of Nautilus

On March 2, 2005 Provident acquired Nautilus Resources, LLC ("Nautilus") for cash consideration of $90.2 million and acquisition costs of $1.2 million. Nautilus was a private oil and gas exploration and production company active in Wyoming, USA. 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 $ 99,877
Working capital 1,237
Asset retirement obligation (1,557)
Financial derivative instrument (8,137)
---------------------------------------------------------------------
$ 91,420
Consideration
Acquisition costs $ 1,237
Cash 90,183
---------------------------------------------------------------------
$ 91,420
---------------------------------------------------------------------
---------------------------------------------------------------------


The result of this acquisition was the non-controlling interest on USOGP operations decreased by 1.4 percent from 5.8 to 4.4 percent.

(ii) Acquisition of BreitBurn

On June 15, 2004 Provident acquired 92 percent of Breitburn Energy LLC (Breitburn) for consideration of $157.4 million and acquisition costs of $8.2 million. Breitburn is a private company (now a limited partnership) active in the oil and gas exploitation and production business in the Los Angeles basin, USA. 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 $ 214,261
Working capital deficiency (8,402)
Non-hedging derivative instruments (25,181)
Other assets 1,028
Asset retirement obligation (2,367)
Non-controlling interest (13,690)
---------------------------------------------------------------------
$ 165,649
---------------------------------------------------------------------
---------------------------------------------------------------------
Consideration
Acquisition costs $ 8,214
Cash 157,435
---------------------------------------------------------------------
$ 165,649
---------------------------------------------------------------------
---------------------------------------------------------------------


On October 4, 2004, the Trust funded Breitburn $58.5 million (USD $45 million) for the Orcutt property acquisition. The result of this funding increased Provident's ownership interest in Breitburn by 2.2 percent to a total of 94.2 percent.

(iii) Acquisition of Olympia

On June 1, 2004 Provident acquired Olympia Energy Inc. for consideration of 13,385,579 Trust units with an ascribed value of $152.9 million and 1,325,000 exchangeable shares with an ascribed value of $15.1 million plus acquisition costs which when netted with option proceeds total $4.7 million. Olympia 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 $ 162,352
Goodwill 106,499
Working capital deficiency (326)
Bank debt (53,852)
Asset retirement obligation (1,909)
Non-hedging derivative instrument (947)
Future income taxes (39,107)
---------------------------------------------------------------------
$ 172,710
---------------------------------------------------------------------
---------------------------------------------------------------------
Consideration
Acquisition costs $ 8,700
Option proceeds (3,985)
Exchangeable shares issued (note 7) 15,132
Trust units issued (note 8) 152,863
---------------------------------------------------------------------
$ 172,710
---------------------------------------------------------------------
---------------------------------------------------------------------


(iv) Acquisition of Viracocha

On June 1, 2004 Provident acquired Viracocha Energy Inc. for consideration of 12,758,386 Trust units with an ascribed value of $145.7 million and 1,325,000 exchangeable shares with an ascribed value of $15.1 million and acquisition costs which when netted with option proceeds total $2.0 million. Viracocha 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 $ 109,907
Goodwill 122,002
Working capital 2,172
Bank debt (49,891)
Capital lease obligation (77)
Deferred lease obligation (98)
Asset retirement obligation (7,895)
Future income taxes (13,294)
---------------------------------------------------------------------
$ 162,826
---------------------------------------------------------------------
---------------------------------------------------------------------
Consideration
Acquisition costs $ 9,000
Option and warrant proceeds (7,007)
Exchangeable shares issued (note 7) 15,132
Trust units issued (note 8) 145,701
---------------------------------------------------------------------
$ 162,826
---------------------------------------------------------------------
---------------------------------------------------------------------


4. Sale of marketing contracts

On May 1, 2005 the Trust disposed of certain oil purchase and sale contracts for net proceeds of $5.5 million and recorded a gain of $5.2 million net of disposal costs.



5. Long-term debt

As at As at
September 30, 2005 Dec 31, 2004
-------------------------------------
Revolving term credit facility $ 182,171 $ 262,750
Convertible debentures 159,079 169,456
---------------------------------------------------------------------
$ 341,250 $ 432,206
---------------------------------------------------------------------
---------------------------------------------------------------------


(i) Revolving term credit facility

At September 30, 2005 Provident had CDN $450 million and USD $100 million term credit facilities. At December 31, 2004 the facility was $410 million.

At September 30, 2005 Provident had letters of credit guaranteeing Provident's performance under certain commercial and other contracts that totaled $27.9 million, resulting in total bank line utilization of 37 percent. The guarantees totaled $31.0 million at December 31, 2004.

(ii) Convertible debentures

On May 31, 2005 the Trust completed the redemption of its 10.5 percent convertible unsecured subordinated debentures that were originally scheduled to mature May 15, 2007. A total of 3.5 million units were issued at the conversion price of $10.70 per unit. A further $3 million cash was paid to the remaining debenture holders that did not convert to trust units at $1,050 for each $1,000 of convertible debenture held plus accrued interest to May 31, 2005 resulting in a loss on redemption of $49,000. Unamortized deferred debt issue costs of $2.5 million, originally incurred on the issuance of the 10.5 percent convertible debentures, were reclassified to trust unit issue costs as a result of the issuance of 3.5 million trust units.

On March 1, 2005 the Trust issued $100.0 million of unsecured convertible subordinated debentures ($95.8 million net of issue costs) with a 6.5 percent coupon rate maturing August 31, 2012. Issue costs have been classified as deferred financing charges. The debentures may be converted into trust units at the option of the holder at a conversion price of $13.75 per trust unit prior to August 31, 2012 and may be redeemed by the Trust under certain circumstances. The unsecured subordinated convertible debentures were initially recorded at fair value of $91.8 million. The difference between the fair value and proceeds of $8.2 million was recorded as equity. The face value of these instruments as at September 30, 2005 was $99.3 million.

On July 6, 2004 the Trust issued $50.0 million of unsecured subordinated convertible debentures ($48.0 million net of issue costs) with an 8.0 percent coupon rate maturing July 31, 2009. Issue costs have been classified as deferred financing charges. The debentures may be converted into trust units at the option of the holder at a conversion price of $12.00 per trust unit prior to July 31, 2009, and may be redeemed by the Trust under certain circumstances. The unsecured subordinated convertible debentures were initially recorded fair value of $48.1 million under accounting rules. The difference between the fair value and proceeds of $1.9 million was recorded as equity. The face value of these instruments as at September 30, 2005 was $34.8 million.

On September 30, 2003 the Trust issued $75 million of unsecured subordinated convertible debentures ($71.8 million net of issues costs) with an 8.75 percent coupon rate maturing December 31, 2008. Issue costs have been classified as deferred financing charges. The debentures may be converted into trust units at the option of the holder at a conversion price of $11.05 per trust unit prior to December 31, 2008, and may be redeemed by the Trust under certain circumstances. The unsecured subordinated convertible debentures were initially recorded at fair value under accounting rules of $70.6 million. The difference between the fair value and proceeds of $4.4 million was recorded as equity. The face value of these instruments as at September 30, 2005 was $36.3 million.

The Trust may elect to satisfy interest and principal obligations by the issue of trust units. For the nine month period ended September 30, 2005, $104.6 million of the face value of debentures were converted to trust units at the election of debenture holders and early extinguishment (2004 - nil). The following table details each convertible debenture:



($000s except
conversion pricing)
As at
September 30, As at
2005 Dec 31, 2004
---------------------------------------------------------------------
Conversion
Price
Carrying Carrying per
Value Face Value Face Maturity unit
(1) Value (1) Value Date (2)
-------------------------------------------------------
10.5%
Convertible May 15,
Debentures $ - $ - $ 49,423 $ 49,881 2007 10.70
6.5%
Convertible Aug. 31,
Debentures 91,724 99,329 - - 2012 13.75
8.0%
Convertible July 31,
Debentures 33,612 34,807 48,199 50,000 2009 12.00
8.75%
Convertible Dec. 31,
Debentures 33,743 36,262 71,834 74,930 2008 11.05
---------------------------------------------------------------------
$159,079 $ 170,398 $169,456 $174,811
---------------------------------------------------------------------
---------------------------------------------------------------------
(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.

The total undiscounted amount of future cash flows required to settle asset retirement obligations related to oil and gas operations is estimated to be $110.4 million. Payments to settle oil and gas asset retirement obligations occur over the operating lives of the assets estimated to be from two to 55 years.

The total undiscounted amount of future cash flows required to settle the midstream asset retirement obligations is estimated to be $26.1 million. The estimated costs include such activities as dismantling, demolition and disposal of the facilities as well as remediation and restoration of the surface land. Payments to settle the midstream asset retirement obligations are expected to occur subsequent to the closure of the facilities and related assets. Settlement of these obligations is expected to occur in 30 to 35 years.



Three months ended Nine months ended
September 30, September 30,
------------------------------------------
2005 2004 2005 2004
------------------------------------------
Carrying amount,
beginning of period $ 43,209 $ 43,133 $ 40,506 $ 33,182
Oil and gas corporate
acquisitions - - 1,557 -
Increase in liabilities
incurred during the
period 767 680 1,219 12,087
Settlement of liabilities
during the period (700) (1,150) (1,695) (3,822)
Decrease in liabilities
due to disposition (13,612) - (13,612) -
Accretion of liability 803 636 2,492 1,852
---------------------------------------------------------------------
Carrying amount,
end of period $ 30,467 $ 43,299 $ 30,467 $ 43,299
---------------------------------------------------------------------
---------------------------------------------------------------------


7. Exchangeable shares - non-controlling interest

The Trust retroactively applied EIC 151 "Exchangeable Securities Issued by a Subsidiary of an Income Trust" as at June 30, 2005. The non-controlling interest on the consolidated balance sheet consists of the fair value of the exchangeable shares upon issuance plus the accumulated earnings attributable to the non-controlling interest. The net income attributable to the non-controlling interest on the consolidated statement of operations represents the cumulative share of net income attributable to the non-controlling interest based on the trust units issuable for exchangeable shares in proportion to total trust units issued and issuable at each period end during the period.

Following is a summary of the non-controlling interest - exchangeable shares for the quarter and nine month periods ended September 30, 2005 and 2004:



Three months ended Nine months ended
September 30, September 30,
------------------------------------------
2005 2004 2005 2004
------------------------------------------
Non-controlling interest,
beginning of period $ 12,979 $ 45,877 $ 35,921 $ 20,542
Exchangeable shares
issued - - - 30,264
Reduction of book value
for conversion to trust
units (3,294) (9,976) (26,501) (14,593)
Net income attributable
to non-controlling
interest 153 (96) 418 (408)
---------------------------------------------------------------------
Non-controlling interest,
end of period $ 9,838 $ 35,805 $ 9,838 $ 35,805


---------------------------------------------------------------------
Accumulated income
attributable to
non-controlling
interest $ 1,900 $ 616 $ 1,900 $ 616
---------------------------------------------------------------------
---------------------------------------------------------------------

The following table details the number of exchangeable shares
converted and outstanding in addition to the associated book value:


Nine months ended September 30,
------------------------------------------
2005 2004
------------------------------------------
Exchangeable shares Number Amount Number Amount
Provident Acquisitions Inc. of Units (000s) of Units (000s)
------------------------------------------
Balance at beginning
of period 336,876 $ 3,675 534,357 $ 5,829
Converted to trust units (336,876) (3,675) (192,882) (2,104)
---------------------------------------------------------------------
Balance, end of period - - 341,475 3,725
Exchange ratio, end
of period - - 1.38057 -
---------------------------------------------------------------------
Trust units issuable upon
conversion, end of period - $ - 471,430 $ 3,725
---------------------------------------------------------------------
---------------------------------------------------------------------


Exchangeable shares Number Amount Number Amount
Provident Energy Ltd.(a) of Units (000s) of Units (000s)
------------------------------------------
Balance at beginning
of period 638,474 $ 6,833 1,279,227 $ 13,689
Converted to trust units - - (640,753) (6,854)
---------------------------------------------------------------------
Balance, end of period 638,474 6,833 638,474 6,835
Exchange ratio, end
of period 1.46949 - 1.30886 -
---------------------------------------------------------------------
Trust units issuable upon
conversion, end of period 938,231 $ 6,833 835,673 $ 6,835
---------------------------------------------------------------------
---------------------------------------------------------------------


Exchangeable shares
(Series B) Number Amount Number Amount
Provident Energy Ltd.(b) of Units (000s) of Units (000s)
------------------------------------------
Balance at beginning
of period 2,095,271 $ 23,931 - $ -
Issued to acquire Olympia
Energy Inc. - - 1,325,000 15,132
Issued to acquire
Viracocha Energy Ltd. - - 1,325,000 15,132
Converted to trust units (1,998,708) (22,826) (493,472) (5,635)
---------------------------------------------------------------------
Balance, end of period 96,563 1,105 2,156,528 24,629
Exchange ratio, end
of period 1.16151 - 1.03405 -
---------------------------------------------------------------------
Trust units issuable upon
conversion, end of period 112,159 $ 1,105 2,229,958 $ 24,629
---------------------------------------------------------------------
---------------------------------------------------------------------
Total Trust units issuable
upon conversion of all
exchangeable shares, end
of period 1,050,390 $ 7,938 3,537,061 $ 35,189
---------------------------------------------------------------------
---------------------------------------------------------------------
(a) Automatic maturity date is January 15, 2006.
(b) Automatic maturity date is June 30, 2006.


8. Unitholders' contributions

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

During the period April 6, 2005 through to May 31, 2005 the Trust issued 3.5 million units at $10.70 per unit to redeem the face value of $42.8 million of the 10.5 percent unsecured convertible debentures. The Trust recognized $46.7million in trust units from the redemption of the 10.5 percent debentures, which is comprised of the carrying value of the debt redeemed and the proportion of the equity component related to the 10.5 percent convertibles debentures.

On March 1, 2005 the Trust issued 8.4 million units at $12.00 per unit for proceeds of $100.8 million ($95.6 million net of issue costs) pursuant to a February 18, 2005 public offering.

On June 1, 2004 the Trust issued 13.4 million and 12.8 million trust units with an ascribed value of $152.9 and $145.7 million as part of the consideration to acquire Olympia Energy Inc. and Viracocha Energy Inc. respectively.

On February 4, 2004 the Trust issued 4.5 million units at $11.20 per unit for proceeds of $50.4 million ($47.9 million net of issue costs) pursuant to a January 22, 2004 public offering.



Nine months ended September 30,
-----------------------------------------------
2005 2004
-----------------------------------------------
Number Amount Number Amount
Trust Units of Units (000s) of Units (000s)
-----------------------------------------------

Balance at beginning
of period 142,226,248 $1,438,393 82,824,688 $ 803,299
Issued to acquire
Olympia Energy Inc. - - 13,385,579 152,863
Issued to acquire
Viracocha Energy Ltd. - - 12,758,386 145,701

Issued for cash 8,400,000 100,800 17,600,000 186,640
Exchangeable share
conversions 2,707,937 26,501 1,561,608 14,593
Issued pursuant to
unit option plan 2,223,109 22,830 478,076 3,872
Issued pursuant to
the distribution
reinvestment plan 1,002,110 12,279 1,199,807 12,502
To be issued pursuant
to the distribution
reinvestment plan 102,137 1,440 172,489 1,859
Debenture conversions 5,701,872 62,328 2,616 28
Redemption of the 10.5%
debentures (note 5) 3,507,570 46,707 - -
Unit issue costs - (7,907) - (9,669)
---------------------------------------------------------------------
Balance at end
of period 165,870,983 $1,703,371 129,983,249 $1,311,688
---------------------------------------------------------------------
---------------------------------------------------------------------


The per trust unit amounts for the quarter ended September 30, 2005 were calculated based on the weighted average number of units outstanding of 164,218,129 which excludes the shares exchangeable into trust units (2004 - 130,910,688). The diluted per trust unit amounts for 2005 are calculated including an additional 324,369 trust units (2004 - 95,641) for the effect of the unit option plan. For the quarter ended September 30, 2005 and 2004, these additional units have been included in the dilution calculation as their effect is dilutive when applied against the net income of the quarter. Provident's convertible debentures and exchangeable shares were excluded in the computation of diluted earnings per unit for the quarter ended September 30, 2005 and 2004 as the effect of including the debentures and exchangeables is anti-dilutive.

The per trust unit amounts for the nine month period ended September 30, 2005 were calculated based on the weighted average number of units outstanding of 156,806,360 which excludes the shares exchangeable into trust units (2004 - 105,574,438). The diluted per trust unit amounts for 2005 are calculated including an additional 324,369 trust units (2004 - 95,641) for the effect of the unit option plan. For the nine month period ended September 30, 2005 and 2004, these additional units have been included in the dilution calculation as their effect is dilutive when applied against the net income of the period Provident's convertible debentures and exchangeable shares are excluded in the computation of diluted earnings per unit for the nine month period ended September 30, 2005 and 2004 as the effect of including the debentures and exchangeables is anti-dilutive.



9. Revenue

Three months ended Nine months ended
September 30, September 30,
---------------------------------------------------------------------
2005 2004 2005 2004
---------------------------------------------------------------------
Gross production
revenue $ 175,668 $ 139,045 $ 455,442 $ 314,350
Product sales and
service revenue 181,017 217,042 612,479 588,238
Royalties (29,974) (28,927) (79,861) (64,357)
---------------------------------------------------------------------
Revenue $ 326,711 $ 327,160 $ 988,060 $ 838,231
---------------------------------------------------------------------
---------------------------------------------------------------------

Realized loss on
financial derivative
instruments (21,763) (24,184) (46,214) (50,673)
Unrealized gain (loss)
on financial derivative (9,888) (15,805) (24,259) (47,136)
---------------------------------------------------------------------
$ 295,060 $ 287,171 $ 917,587 $ 740,422
---------------------------------------------------------------------
---------------------------------------------------------------------

Change in unrealized loss
on financial derivative
instruments $ (9,301) $ (10,072) $ (22,703) $ (28,068)
Amortization of loss on
financial derivative
instruments (587) (5,733) (1,556) (19,068)
---------------------------------------------------------------------
Unrealized gain (loss)
on financial derivative
instruments $ (9,888) $ (15,805) $ (24,259) $ (47,136)
---------------------------------------------------------------------
---------------------------------------------------------------------


The realized loss on financial derivative instruments for the quarter ended September 30, 2005 of $21.8 million (2004 - $24.2 million) and for the nine months ended September 30, 2005 of $46.2 million (2004 - $50.7 million) relates to the cash settlement on derivative instruments.

10. Non-cash general & administrative

(i) Unit option plan

The Trust option plan (the "Plan") is administered by the Board of Directors of Provident. Under the Plan, all directors, officers and employees of Provident, are eligible to participate in the Plan. There are 8,000,000 trust units reserved for the Trust option plan. Options are granted at a "strike price" which is not less than the closing price of the units on the Toronto Stock Exchange on the last trading day preceding the grant. In certain circumstances, based upon the cash distributions made on the trust units, the strike price may be reduced at the time of exercise of the option at the discretion of the option holder. Options vest six months after grant and every year thereafter in equal increments. In October 2005, a restricted/performance unit program (see (iii)) was approved. This program is intended to replace the unit option plan. Unit options in existence will continue to be outstanding.



Nine months ended September 30,
-----------------------------------------------
2005 2004
-----------------------------------------------
Weighted Weighted
Number of Average Number of Average
Options Exercise Options Exercise
-----------------------------------------------
Outstanding,
beginning of period 5,200,331 $ 11.01 4,008,744 $ 11.06
Granted 296,200 11.73 478,750 10.74
Exercised (2,223,109) 10.97 (478,076) 10.95
Forfeited (25,064) 10.97 (49,497) 11.09
---------------------------------------------------------------------
Outstanding,
end of period 3,248,358 11.10 3,959,921 11.04
---------------------------------------------------------------------
Exercisable,
end of period 1,551,313 $ 11.18 2,071,673 $ 11.07
---------------------------------------------------------------------
---------------------------------------------------------------------


At September 30, 2005, the Trust had 3,248,358 options outstanding with strike prices ranging between $8.91 and $12.14 per unit. The weighted average remaining contractual life of the options is 2.69 years and the weighted average exercise price is $11.10 per unit excluding average potential reductions to the strike prices of $0.89 per unit.

At September 30, 2004, the Trust had 3,959,921 options outstanding with strike prices ranging between $8.40 and $12.39 per unit. The weighted average remaining contractual life of the options was 2.5 years and the weighted average exercise price was $11.04 per unit excluding average potential reductions to the strike prices of $1.30 per unit.

On December 31, 2004 the Trust prospectively applied the fair value based method of accounting for the Plan. Previously, the Trust applied the intrinsic value methodology due to the uncertainties of future expected distributions. The Trust now uses the Black-Scholes option-pricing model to calculate the estimated fair value of the outstanding options issued on or after January 1, 2003 at their issue date. The Trust has reevaluated the assumptions required to calculate the fair value of options and considers the estimates required to calculate the fair value reasonably estimated at the time of the issue of the options.

For the quarter ended September 30, 2005 the Trust recorded unit-based compensation (non-cash general and administrative) of $0.3 million, for the 5.6 million options granted on or after January 1, 2003 (2004 - expense of $1.9 million).

In 2005 the Trust recorded unit-based compensation (non-cash general and administrative) of $0.8 million, for the 5.6 million options granted on or after January 1, 2003 (2004 - expense of $1.2 million).

As at September 30, 2005, the following assumptions are the weighted averages of the individual assumptions applied at each grant date to arrive at an estimate of fair value of all granted options on or after January 1, 2003 of $3.8 million:



Three months ended For the year ended
September 30, Dec 31, Dec 31,
2005 2004 2003
------------------------------------------
Expected annual dividend 8.00% 8.00% 8.00%
Expected volatility 19.88% 20.18% 19.46%
Risk - free interest rate 3.26% 3.30% 3.66%
Expected life of option (yrs) 3.31 3.31 3.31
Expected forfeitures - - -
Fair Value of Granted
Options $0.2 million $1.2 million $2.4 million
---------------------------------------------------------------------
---------------------------------------------------------------------


The following table reconciles the year-to-date movement in the
contributed surplus balance:

Three months ended Nine months ended
September 30, September 30,
------------------------------------------
2005 2004 2005 2004
------------------------------------------
Contributed surplus,
beginning of the period $ 1,271 $ 585 $ 2,002 $ 1,305
Compensation expense 256 1,860 755 1,165
Benefit on options
exercised charged to
unitholders' equity (128) (76) (1,358) (101)
---------------------------------------------------------------------
Contributed surplus,
end of the period $ 1,399 $ 2,369 $ 1,399 $ 2,369
---------------------------------------------------------------------
---------------------------------------------------------------------


(ii) Unit appreciation rights

During 2004, the Trust put in place a program whereby certain employees of its U.S subsidiary are granted unit appreciation rights ("UAR's") which entitle the employee to receive cash compensation in relation to the value of a specified number of underlying notional trust units. UAR's vest evenly over a period of three years commencing one year after grant and expire after four years.

The UAR's, upon vesting, provide certain employees entitlement to receive a cash payment equal to the excess of the market price of the Trust's units over the exercise price of the right less notionally accrued distributions in excess of an eight percent return.

The fair value associated with the UAR's is expensed in the statement of income over the vesting period. During the quarter, the Trust recorded compensation costs of $2.2 million with respect to the outstanding UAR's (2004 - nil). For the nine month period ended September 30, 2005, the Trust recorded compensation costs of $4.1million with respect to the outstanding UAR's (2004 - nil).

The following table summarizes the information about UAR's:



As at
September 30, 2005
------------------------------------------
Number of Units Weighted Average
Appreciation Rights Exercise Price
------------------------------------------
Outstanding, beginning
of year 976,000 $ 7.98
Granted 147,000 $ 10.01
Exercised 281,755 7.91
Forfeited 16,000 8.04
---------------------------------------------------------------------
Outstanding, end of quarter 825,245 $ 8.29
---------------------------------------------------------------------
Exerciseable, end of quarter 21,578 7.94
---------------------------------------------------------------------
---------------------------------------------------------------------
Weighted average remaining
contract life 2.84
Average reductions to exercise price $1.04
---------------------------------------------------------------------
---------------------------------------------------------------------


(iii) Restricted/Performance units

In October 2005 the board of directors approved a previously proposed program whereby certain employees of the Trust's Canadian subsidiaries will be granted restricted trust units (RTU's) and/or performance trust units (PTU's), both of which entitle the employee to receive cash compensation in relation to the value of a specified number of underlying notional trust units. The grants are based on personal performance objectives. This plan replaces the unit options plan for 2005 and subsequent years. RTU's vest evenly over a period of three years commencing one year after grant. Payments are made on the anniversary dates of the RTU to the employees entitled to receive them on the basis of a cash payment equal to the value of the underlying notional units. PTU's vest three years from the date of grant and can be increased to a maximum of double the PTU's granted or a minimum of nil PTU's depending on the Trust's performance vis-a-vis other trusts' performance based on total returns. PTU's entitle employees to receive cash payments equal to the market price of the underlying notional Trust's Units.

The estimated fair value associated with the RTU's and PTU's is expensed in the statement of income over the vesting period. During the nine months ended September 30, 2005, the Trust recorded compensation costs of $1.5 million with respect to the expected issue of RTU's and PTU's (2004 - nil).

11. Reconciliation of cash flow and distributions



Three months ended Nine months ended
September 30, September 30,
------------------------------------------
2005 2004 2005 2004
------------------------------------------
Cash provided by
operating activities $ 81,965 $ 44,069 $ 185,873 $ 120,012
Change in non cash
working capital 3,653 8,911 27,322 4,780
Site restoration
expenditures 700 1,096 1,695 2,083
---------------------------------------------------------------------
Cash flow from operations 86,318 54,076 214,890 126,875
Cash reserved for
financing and investing
activities (26,985) (7,587) (46,822) (14,311)
---------------------------------------------------------------------
Cash distributions to
unitholders 59,333 46,489 168,068 112,564
Accumulated cash
distributions, beginning
of period 521,381 314,093 412,646 248,018
---------------------------------------------------------------------
Accumulated cash
distributions, paid and
declared, end of period $580,714 $ 360,582 $ 580,714 $ 360,582
---------------------------------------------------------------------
Cash distributions per
unit $ 0.36 $ 0.36 $ 1.08 $ 1.08
---------------------------------------------------------------------
---------------------------------------------------------------------


Cash reserved for financing and investing activities is a discretionary amount and represents the difference between cash flow from operations less distributions.

12. Subsequent event

On October 27, 2005, the Trust announced that it has agreed to acquire the natural gas liquids (NGL) business of EnCana Corporation, for a purchase price of approximately $697 million, plus working capital and other adjustments, estimated to be $80 million. The acquired business includes interests in an interconnected set of NGL extraction, transportation, storage, fractionation and distribution facilities, with current throughput of approximately 25,000 barrels per day of ethane and approximately 13,500 barrels per day of propane-plus. Also included is NGL marketing company Kinetic Resources.

In conjunction with the acquisition, Provident has entered into an underwriter's agreement and issued a prospectus offering to issue 21.8 million subscription receipts. Each subscription receipt is offered at a price of $12.60 and entitles the holder to receive one trust unit upon completion of the acquisition of the NGL business. Provident has also granted the underwriters an option to purchase up to an additional 3.2 million subscription receipts during the offering. In addition, Provident will issue $150.0 million principal amount of 6.50 percent convertible extendible unsecured subordinated debentures with an expected maturity date of April 30, 2011. The remainder of the purchase price will be financed with bank debt. Concurrent with this announcement, Provident also increased its Canadian dollar revolving term credit facility by $300 million to a total of $750 million, with terms similar to the existing facility.

To ensure sufficient funds are available to complete the acquisition, Provident has obtained a bridge financing facility amounting to $474 million. The bridge facility will be utilized to complete the acquisition only in the event the subscription receipt and convertible debenture offerings are not completed.

The transaction and securities offerings are expected to close in the fourth quarter of 2005.

13. Comparative balances

Certain comparative numbers have been restated to conform to the current period's presentation.

14. 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 services and marketing.

Oil and natural gas production in Canada and the United States includes exploitation, development and production of crude oil and natural gas reserves. Midstream services and marketing 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 and marketing business that operates in Canada. Interest and long-term debt have been allocated to the business segments on the basis of invested capital at net book value.



Three months ended September 30, 2005
------------------------------------------------

Canada Oil and United States Oil Total Oil &
Natural Gas and Natural Gas Natural Gas
Production Production Production
------------------------------------------------

Revenue
Gross production revenue $ 129,293 $ 46,375 $ 175,668
Royalties (25,434) (4,540) (29,974)
Product sales and service
revenue - - -
Realized gain (loss) on
financial derivative
instruments (15,841) (5,780) (21,621)
---------------------------------------------------------------------
88,018 36,055 124,073

Expenses
Cost of goods sold - - -
Production, operating and
maintenance 23,949 10,652 34,601
Transportation 1,390 - 1,390
Foreign exchange (gain)
loss and other (1,835) - (1,835)
General and administrative 5,377 2,870 8,247
---------------------------------------------------------------------
28,881 13,522 42,403
---------------------------------------------------------------------

Earnings before interest,
taxes, depletion,
depreciation, accretion
and non-cash revenue 59,137 22,533 81,670

Non-cash revenue
Unrealized gain (loss) on
financial derivative
instruments (7,434) (263) (7,697)
Amortization of loss on
financial derivative
instruments (587) - (587)
---------------------------------------------------------------------
(8,021) (263) (8,284)
---------------------------------------------------------------------

Other expenses
Depletion, depreciation
and accretion 39,363 7,147 46,510
Loss on redemption of
convertible debentures - - -
Interest on bank debt 964 324 1,288
Interest & accretion on
convertible debentures 2,923 981 3,904
Amortization of deferred
financing charges 218 72 290
Unrealized foreign
exchange gain - - -
Non-cash general and
Administrative 256 2,175 2,431
Internal management charge (270) 270 -
Gain on sale of marketing
contracts - - -
Capital, income and
withholding taxes 766 2,554 3,320
Future income tax expense
(recovery) 4,298 - 4,298
---------------------------------------------------------------------
48,518 13,523 62,041
Non-controlling interest
- USOGP - 527 527
Non-controlling interest
- Exchangeables 19 97 116
---------------------------------------------------------------------

Net income for the period $ 2,579 $ 8,123 $ 10,702
---------------------------------------------------------------------
---------------------------------------------------------------------

Three months ended September 30, 2005
------------------------------------------------

Midstream
Services and Inter-segment
Marketing Elimination Total
------------------------------------------------

Revenue
Gross production revenue $ - $ - $ 175,668
Royalties - - (29,974)
Product sales and service
revenue 181,017 - 181,017
Realized gain (loss) on
financial derivative
instruments (142) - (21,763)
---------------------------------------------------------------------
180,875 - 304,948

Expenses
Cost of goods sold 157,749 - 157,749
Production, operating and
maintenance 8,614 - 43,215
Transportation - - 1,390
Foreign exchange (gain)
loss and other (138) - (1,973)
General and administrative 1,672 - 9,919
---------------------------------------------------------------------
167,897 - 210,300
---------------------------------------------------------------------

Earnings before interest,
taxes, depletion,
depreciation, accretion and
non-cash revenue 12,978 - 94,648

Non-cash revenue
Unrealized gain (loss) on
financial derivative
instruments (1,604) - (9,301)
Amortization of loss on
financial derivative
instruments - - (587)
---------------------------------------------------------------------
(1,604) - (9,888)
---------------------------------------------------------------------

Other expenses
Depletion, depreciation and
accretion 2,511 - 49,021
Loss on redemption of
convertible debentures - - -
Interest on bank debt 247 - 1,535
Interest & accretion on
convertible debentures 747 - 4,651

Amortization of deferred
financing charges 55 - 345
Unrealized foreign exchange
gain 93 - 93
Non-cash general and
administrative - - 2,431
Internal management charge - - -
Gain on sale of marketing
contracts - - -
Capital, income and
withholding taxes - - 3,320
Future income tax expense
(recovery) - - 4,298
---------------------------------------------------------------------
3,653 - 65,694
Non-controlling interest
- USOGP - - 527
Non-controlling interest
- Exchangeables 37 - 153
---------------------------------------------------------------------

Net income for the period $ 7,684 $ - $ 18,386
---------------------------------------------------------------------
---------------------------------------------------------------------



Three months ended September 30, 2005
------------------------------------------------

Canada Oil and United States Oil Total Oil &
Natural Gas and Natural Gas Natural Gas
Production Production Production
------------------------------------------------

Selected balance sheet items

Capital Assets
Property, plant and
equipment net $ 656,152 $ 361,796 $ 1,017,948
Goodwill 330,944 - 330,944


Capital Expenditures
Property, plant and
equipment net 27,776 11,209 38,985
Property, plant and
equipment through
corporate acquisitions - - -

Goodwill additions - - -

Working capital
Accounts receivable 74,819 19,547 94,366
Petroleum product
inventory - - -
Accounts payable and
accrued liabilities 152,321 40,240 192,561
Long-term debt $ 115,509 $ 37,374 $ 152,883
---------------------------------------------------------------------
---------------------------------------------------------------------

Three months ended September 30, 2005
------------------------------------------------

Midstream
Services and Inter-segment
Marketing Elimination Total
------------------------------------------------

Selected balance sheet items

Capital Assets
Property, plant and
equipment net $ 269,045 $ - $ 1,286,993
Goodwill - - 330,944

Capital Expenditures
Property, plant and
equipment net 1,097 - 40,082
Property, plant and
equipment through
corporate acquisitions - - -

Goodwill additions - - -

Working capital
Accounts receivable 92,862 (11,170) 176,058
Petroleum product inventory 35,115 - 35,115
Accounts payable and
accrued liabilities 10,319 (11,170) 191,710
Long-term debt $ 29,288 $ - $ 182,171
---------------------------------------------------------------------
---------------------------------------------------------------------



Three months ended September 30, 2004 (1)
------------------------------------------------

Canada Oil and United States Oil Total Oil &
Natural Gas and Natural Gas Natural Gas
Production Production Production
------------------------------------------------

Revenue
Gross production revenue $ 121,539 $ 17,506 $ 139,045
Royalties (27,251) (1,676) (28,927)
Product sales and service
revenue - - -
Realized gain/(loss) on
non-hedging derivative
instruments (20,645) (344) (20,989)
---------------------------------------------------------------------
73,643 15,486 89,129

Expenses
Cost of goods sold - - -
Operating Expenses 27,010 5,167 32,177
Transportation 1,436 - 1,436
Foreign exchange
(gain)/loss and other - (1,989) (1,989)
General and administrative 4,277 1,461 5,738
---------------------------------------------------------------------
32,723 4,639 37,362
---------------------------------------------------------------------

Earnings before interest,
taxes, depletion,
depreciation, accretion
and non-cash revenue 40,920 10,847 51,767

Non-cash revenue
Unrealized gain/(loss) on
non-hedging derivative
instruments (11,977) - (11,977)
Amortization of (loss) on
non-hedging derivative
instruments (5,733) - (5,733)
---------------------------------------------------------------------
(17,710) - (17,710)
---------------------------------------------------------------------

Other expenses
Depletion, depreciation
and accretion 46,327 2,314 48,641
Interest on long-term debt 1,966 155 2,121
Interest and accretion on
convertible debentures 3,749 532 4,281
Amortization of deferred
financing charges 244 40 284
Unrealized foreign exchange
(gain) loss - 952 952
Non-cash general and
administrative 1,689 - 1,689
Capital taxes 1,085 - 1,085
Current and
withholding taxes - 191 191
Future income tax expenses
(recovery) (8,003) - (8,003)
---------------------------------------------------------------------
47,057 4,184 51,241
Non-controlling interest
- USOGP 566 566
Non-controlling interest
- Exchangeables (526) 132 (394)
---------------------------------------------------------------------

Net income (loss) for the
period $(23,321) $ 5,965 $ (17,356)
---------------------------------------------------------------------
---------------------------------------------------------------------
(1) Restated - note 2

Three months ended September 30, 2004 (1)
------------------------------------------------

Midstream
Services and Inter-segment
Marketing Elimination Total
------------------------------------------------

Revenue
Gross production revenue $ - $ - $ 139,045
Royalties - - (28,927)
Product sales and service
revenue 290,874 (73,832) 217,042
Realized gain/(loss) on
non-hedging derivative
instruments (3,195) - (24,184)
---------------------------------------------------------------------
287,679 (73,832) 302,976

Expenses
Cost of goods sold 266,574 (73,832) 192,742
Operating Expenses 8,010 - 40,187
Transportation - - 1,436
Foreign exchange
(gain)/loss and other 397 (1,592)
General and administrative 1,712 - 7,450
---------------------------------------------------------------------
276,693 (73,832) 240,223
---------------------------------------------------------------------

Earnings before interest,
taxes, depletion,
depreciation, accretion
and non-cash revenue 10,986 - 62,753

Non-cash revenue
Unrealized gain/(loss) on
non-hedging derivative
instruments 1,905 - (10,072)
Amortization of (loss) on
non-hedging derivative
instruments - - (5,733)
---------------------------------------------------------------------
1,905 - (15,805)
---------------------------------------------------------------------

Other expenses
Depletion, depreciation
and accretion 2,264 - 50,905
Interest on long-term debt 1,257 - 3,378
Interest and accretion on
convertible debentures 427 - 4,708
Amortization of deferred
financing charges 75 - 359
Unrealized foreign exchange
(gain) loss - - 952
Non-cash general and
administrative 171 - 1,860
Capital taxes 117 - 1,202
Current and
withholding taxes 135 - 326
Future income tax
expenses (recovery) (4,988) - (12,991)
---------------------------------------------------------------------
(542) - 50,699
Non-controlling interest
- USOGP - - 566
Non-controlling interest
- Exchangeables 298 - (96)
---------------------------------------------------------------------

Net income (loss) for the
period $ 13,135 $ - $ (4,221)
---------------------------------------------------------------------
---------------------------------------------------------------------
(1) Restated - note 2



Three months ended September 30, 2004 (1)
------------------------------------------------

Canada Oil and United States Oil Total Oil &
Natural Gas and Natural Gas Natural Gas
Production Production Production
------------------------------------------------

Selected balance sheet items

Capital Expenditures
Property, plant and
equipment net 22,205 8,173 30,378
Property, plant and
equipment through
corporate acquisitions - - -

Goodwill additions 7,006 - 7,006

Working capital
Accounts receivable 74,263 9,802 84,065
Petroleum product inventory - - -
Accounts payable and
accrued liabilities 100,590 23,618 124,208
Long-term debt $ 200,921 $ 3,097 $ 204,018
---------------------------------------------------------------------
---------------------------------------------------------------------
(1) Restated - note 2

Three months ended September 30, 2004 (1)
------------------------------------------------

Midstream
Services and Inter-segment
Marketing Elimination Total
------------------------------------------------

Selected balance sheet items

Capital Expenditures
Property, plant and
equipment net $ 337 $ - $ 30,715
Property, plant and
equipment through
corporate acquisitions 1,300 - 1,300

Goodwill additions - - 7,006

Working capital
Accounts receivable 104,933 (16,972) 172,026
Petroleum product inventory 26,577 - 26,577
Accounts payable and
accrued liabilities 90,711 (16,972) 197,947
Long-term debt $ 120,000 $ - $ 324,018
---------------------------------------------------------------------
---------------------------------------------------------------------
(1) Restated - note 2



Nine months ended September 30, 2005
------------------------------------------------

Canada Oil and United States Oil Total Oil &
Natural Gas and Natural Gas Natural Gas
Production Production Production
------------------------------------------------

Revenue
Gross production revenue $ 342,216 $ 113,226 $ 455,442
Royalties (68,918) (10,943) (79,861)
Product sales and service
revenue - - -
Realized gain (loss) on
financial derivative
instruments (35,135) (11,448) (46,583)
---------------------------------------------------------------------
238,163 90,835 328,998

Expenses
Cost of goods sold - - -
Production, operating and
maintenance 71,841 28,003 99,844
Transportation 4,418 - 4,418
Foreign exchange loss
(gain) and other (1,066) (504) (1,570)
General and administrative 14,825 6,965 21,790
---------------------------------------------------------------------
90,018 34,464 124,482
---------------------------------------------------------------------

Earnings before interest,
taxes, depletion,
depreciation, accretion
and non-cash revenue 148,145 56,371 204,516

Non-cash revenue
Unrealized loss on financial
derivative instruments (11,294) (8,908) (20,202)
Amortization of loss on
financial derivative
instruments (1,556) - (1,556)
---------------------------------------------------------------------
(12,850) (8,908) (21,758)
---------------------------------------------------------------------

Other expenses
Depletion, depreciation
and accretion 122,120 18,931 141,051
Loss on redemption of
convertible debentures 31 10 41
Interest on bank debt 4,257 1,428 5,685
Interest & accretion on
convertible debentures 10,521 3,531 14,052
Amortization of deferred
financing charges 568 190 758
Unrealized foreign
exchange gain - - -
Non-cash general and
administrative recovery 755 4,098 4,853
Internal management charge (1,431) 1,431 -
Gain on sale of marketing
contracts - - -
Capital, current and
withholding taxes 3,677 6,924 10,601
Future income tax recovery (5,534) - (5,534)
---------------------------------------------------------------------
134,964 36,543 171,507
Non-controlling interest
- USOGP - 926 926
Non-controlling interest
- Exchangeables (85) 73 (12)
---------------------------------------------------------------------

Net income (loss) for the
period $ 416 $ 9,921 $ 10,337
---------------------------------------------------------------------
---------------------------------------------------------------------

Nine months ended September 30, 2005
------------------------------------------------

Midstream
Services and Inter-segment
Marketing Elimination Total
------------------------------------------------

Revenue
Gross production revenue - - 455,442
Royalties - - (79,861)
Product sales and service
revenue 702,899 (90,420) 612,479
Realized gain (loss) on
financial derivative
instruments 369 - (46,214)
---------------------------------------------------------------------
703,268 (90,420) 941,846

Expenses
Cost of goods sold 631,968 (90,420) 541,548
Production, operating
and maintenance 24,666 - 124,510
Transportation - - 4,418
Foreign exchange loss
(gain) and other (255) - (1,825)
General and administrative 5,766 27,556
---------------------------------------------------------------------
662,145 (90,420) 696,207
---------------------------------------------------------------------

Earnings before interest,
taxes, depletion,
depreciation, accretion
and non-cash revenue 41,123 - 245,639

Non-cash revenue
Unrealized loss on financial
derivative instruments (2,501) - (22,703)
Amortization of loss on
financial derivative

instruments - - (1,556)
---------------------------------------------------------------------
(2,501) - (24,259)
---------------------------------------------------------------------

Other expenses
Depletion, depreciation
and accretion 7,520 - 148,571
Loss on redemption of
convertible debentures 8 - 49
Interest on bank debt 1,090 - 6,775
Interest & accretion on
convertible debentures 2,692 - 16,744
Amortization of deferred
financing charges 145 - 903
Unrealized foreign
exchange gain (163) - (163)
Non-cash general and
administrative recovery - - 4,853
Internal management charge - - -
Gain on sale of marketing
contracts (5,188) - (5,188)
Capital, current and
withholding taxes - - 10,601
Future income tax recovery - - (5,534)
---------------------------------------------------------------------
6,104 - 177,611
Non-controlling interest
- USOGP - - 926
Non-controlling interest
- Exchangeables 430 - 418
---------------------------------------------------------------------

Net income (loss) for the
period $ 32,088 $ - $ 42,425
---------------------------------------------------------------------
---------------------------------------------------------------------



Nine months ended September 30, 2005
------------------------------------------------

Canada Oil and United States Oil Total Oil &
Natural Gas and Natural Gas Natural Gas
Production Production Production
------------------------------------------------

Selected balance sheet items

Capital Assets
Property, plant and
equipment net $ 656,152 $ 361,796 $ 1,017,948
Goodwill 330,944 - 330,944

Capital Expenditures
Property, plant and
equipment net 63,048 41,373 104,421
Property, plant and
equipment through
corporate acquisitions - 99,877 99,877

Goodwill additions - - -

Working capital
Accounts receivable 74,819 19,547 94,366
Petroleum product inventory - - -
Accounts payable and
accrued liabilities 152,321 40,240 192,561


Long-term debt $ 115,509 $ 37,374 $ 152,883
---------------------------------------------------------------------
---------------------------------------------------------------------

Nine months ended September 30, 2005
------------------------------------------------

Midstream
Services and Inter-segment
Marketing Elimination Total
------------------------------------------------

Selected balance sheet items

Capital Assets
Property, plant and
equipment net $ 269,045 $ - $ 1,286,993
Goodwill - - 330,944

Capital Expenditures
Property, plant and
equipment net 1,747 - 106,168
Property, plant and
equipment through
corporate acquisitions - - 99,877

Goodwill additions - - -



Working capital
Accounts receivable 92,862 (11,170) 176,058
Petroleum product inventory 35,115 - 35,115
Accounts payable and
accrued liabilities 10,319 (11,170) 191,710
Long-term debt $ 29,288 $ - $ 182,171
---------------------------------------------------------------------
---------------------------------------------------------------------



Nine months ended September 30, 2004 (1)
------------------------------------------------

Canada Oil and United States Oil Total Oil &
Natural Gas and Natural Gas Natural Gas
Production Production Production
------------------------------------------------

Revenue
Gross production revenue $ 294,687 $ 20,178 $ 314,865
Royalties (62,389) (1,968) (64,357)
Product sales and service
revenue - - -
Realized loss on financial
derivative instruments (46,854) (344) (47,198)
---------------------------------------------------------------------
185,444 17,866 203,310

Expenses
Cost of goods sold - - -
Production, operating and
maintenance 63,899 6,184 70,083
Transportation 3,364 - 3,364
Foreign exchange gain
(loss) and other - (1,989) (1,989)
General and administrative 12,521 1,849 14,370
---------------------------------------------------------------------
79,784 6,044 85,828
---------------------------------------------------------------------

Earnings before interest,
taxes, depletion,
depreciation, accretion
and non-cash revenue 105,660 11,822 117,482

Non-cash revenue
Unrealized gain/(loss) on
non-hedging derivative
instruments (28,915) - (28,915)
Amortization of gain/(loss)
on non-hedging derivative
instruments (19,068) - (19,068)
---------------------------------------------------------------------
(47,983) - (47,983)
---------------------------------------------------------------------

Other expenses
Depletion, depreciation
and accretion 114,956 2,584 117,540
Interest on bank debt 4,594 580 5,174
Interest and accretion on
convertible debentures 8,443 897 9,340
Amortization of deferred
financing charges 716 40 756
Unamortized foreign
exchange (gain) loss - (1,567) (1,567)
Non-cash general and
administrative 1,049 - 1,049
Capital taxes 2,713 157 2,870
Current and
withholding taxes 292 191 483
Future income tax expense
(recovery) (27,879) - (27,879)
---------------------------------------------------------------------
104,884 2,882 107,766
Non-controlling interest
- USOGP - 696 696
Non-controlling interest
- Exchangeables (1,078) 182 (896)
---------------------------------------------------------------------

Net income (loss) for the
period $ (46,129) $ 8,062 $ (38,067)
---------------------------------------------------------------------
---------------------------------------------------------------------
(1) Restated - note 2

Nine months ended September 30, 2004 (1)
------------------------------------------------

Midstream
Services and Inter-segment
Marketing Elimination Total
------------------------------------------------

Revenue
Gross production revenue $ - $ (515) $ 314,350
Royalties - - (64,357)
Product sales and service
revenue 742,573 (154,335) 588,238
Realized loss on financial
derivative instruments (3,475) - (50,673)
---------------------------------------------------------------------
739,098 (154,850) 787,558

Expenses
Cost of goods sold 674,845 (154,850) 519,995
Production, operating
and maintenance 27,889 - 97,972
Transportation - - 3,364
Foreign exchange gain
(loss) and other 149 (1,840)
General and administrative 4,087 18,457
---------------------------------------------------------------------
706,970 (154,850) 637,948
---------------------------------------------------------------------

Earnings before interest,
taxes, depletion,
depreciation, accretion
and non-cash revenue 32,128 - 149,610

Non-cash revenue
Unrealized gain/(loss) on
non-hedging derivative
instruments 847 - (28,068)
Amortization of gain/(loss)
on non-hedging derivative
instruments - - (19,068)
---------------------------------------------------------------------
847 - (47,136)
---------------------------------------------------------------------

Other expenses
Depletion, depreciation
and accretion 6,837 - 124,377
Interest on bank debt 3,277 - 8,451
Interest and accretion on
convertible debentures 3,017 - 12,357
Amortization of deferred
financing charges 321 - 1,077
Unamortized foreign
exchange (gain) loss - (1,567)
Non-cash general and
administrative 116 - 1,165
Capital taxes 504 - 3,374
Current and withholding taxes 135 - 618
Future income tax expense
(recovery) (2,698) - (30,577)
---------------------------------------------------------------------
11,509 - 119,275
Non-controlling interest
- USOGP - - 696
Non-controlling interest
- Exchangeables 488 - (408)
---------------------------------------------------------------------

Net income (loss) for the
period $ 20,978 $ - $ (17,089)
---------------------------------------------------------------------
---------------------------------------------------------------------
(1) Restated - note 2



Nine months ended September 30, 2004 (1)
------------------------------------------------

Canada Oil and United States Oil Total Oil &
Natural Gas and Natural Gas Natural Gas
Production Production Production
------------------------------------------------

Selected balance sheet items

Capital Expenditures
Property, plant and
equipment net $ 48,564 $ 8,750 $ 57,314
Property, plant and
equipment through
corporate acquisitions 272,316 212,904 485,220

Goodwill additions 228,501 - 228,501

Working capital
Accounts receivable 74,263 9,802 84,065
Petroleum product inventory - - -
Accounts payable and
accrued liabilities 100,590 23,618 124,208
Long-term debt $ 200,921 $ 3,097 $ 204,018
---------------------------------------------------------------------
---------------------------------------------------------------------
(1) Restated - note 2

Nine months ended September 30, 2004 (1)
------------------------------------------------

Midstream
Services and Inter-segment
Marketing Elimination Total
------------------------------------------------

Selected balance sheet items

Capital Expenditures
Property, plant and
equipment net $ 1,245 $ - $ 58,559
Property, plant and
equipment through
corporate acquisitions 1,300 - 486,520

Goodwill additions - - 228,501

Working capital
Accounts receivable 104,933 (16,972) 172,026
Petroleum product inventory 26,577 - 26,577
Accounts payable and
accrued liabilities 90,711 (16,972) 197,947
Long-term debt $ 120,000 $ - $ 324,018
---------------------------------------------------------------------
---------------------------------------------------------------------
(1) Restated - note 2


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